____________________________________________________________________________________

[JUNE2008FORM10QFINAL001.JPG]


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q


[X]

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE     
SECURITIES EXCHANGE ACT OF 1934

 

 

 

For the Quarterly Period Ended June 30, 2008      

 

OR     

[  ]

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE     
SECURITIES EXCHANGE ACT OF 1934

 

 

 

For the transition period from ____________ to ____________


Commission
File Number

Registrant; State of Incorporation;
Address; and Telephone Number

I.R.S. Employer
Identification No.

 

 

 

1-5324

NORTHEAST UTILITIES
(a Massachusetts voluntary association)
One Federal Street
Building 111-4
Springfield, Massachusetts 01105
Telephone:  (413) 785-5871

04-2147929

 

 

 

0-00404

THE CONNECTICUT LIGHT AND POWER COMPANY
(a Connecticut corporation)
107 Selden Street
Berlin, Connecticut 06037-1616
Telephone:  (860) 665-5000

06-0303850

 

 

 

1-6392

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
(a New Hampshire corporation)
Energy Park
780 North Commercial Street
Manchester, New Hampshire 03101-1134
Telephone:  (603) 669-4000

02-0181050

 

 

 

0-7624

WESTERN MASSACHUSETTS ELECTRIC COMPANY
(a Massachusetts corporation)
One Federal Street
Building 111-4
Springfield, Massachusetts 01105
Telephone:  (413) 785-5871

04-1961130

____________________________________________________________________________________





Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days:


 

Yes

No

 

 

 

 

Ö

 


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.  (check one):


 

Large
Accelerated Filer

 

Accelerated
Filer

 

Non-accelerated
Filer

 

 

 

 

 

 

Northeast Utilities

Ö

 

 

 

 

The Connecticut Light and Power Company

 

 

 

 

Ö

Public Service Company of New Hampshire

 

 

 

 

Ö

Western Massachusetts Electric Company

 

 

 

 

Ö


Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act):


 

Yes

No

 

 

 

Northeast Utilities

 

Ö

The Connecticut Light and Power Company

 

Ö

Public Service Company of New Hampshire

 

Ö

Western Massachusetts Electric Company

 

Ö


Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date:

Company - Class of Stock

Outstanding at July 31, 2008

Northeast Utilities
Common stock, $5.00 par value


155,560,418 shares

 

 

The Connecticut Light and Power Company
Common stock, $10.00 par value


6,035,205 shares

 

 

Public Service Company of New Hampshire
Common stock, $1.00 par value


301 shares

 

 

Western Massachusetts Electric Company
Common stock, $25.00 par value


434,653 shares


Northeast Utilities holds all of the 6,035,205 shares, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, respectively.  


Public Service Company of New Hampshire and Western Massachusetts Electric Company each meet the conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) of Form 10-Q.








GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that are found in this report.  

 

 

NU COMPANIES,  SEGMENTS OR INVESTMENTS:

 

 

Boulos

E.S. Boulos Company

CL&P

The Connecticut Light and Power Company

Con Edison

Consolidated Edison, Inc.

CRC

CL&P Receivables Corporation

HWP

Holyoke Water Power Company

Mt. Tom

Mt. Tom generating plant

NGC

Northeast Generation Company

NGS

Northeast Generation Services Company and subsidiaries

NU or the company

Northeast Utilities

NU Enterprises

At June 30, 2008, NU Enterprises, Inc. is the parent company of Select Energy, NGS, and Boulos.  For further information, see Note 10, "Segment Information," to the condensed consolidated financial statements.

NU parent and other companies

NU parent and other companies is comprised of NU parent, Northeast Utilities Service Company, HWP (since January 1, 2007) and other subsidiaries, including The Rocky River Realty Company and The Quinnehtuk Company (both real estate subsidiaries), Mode 1 Communications, Inc. (telecommunications) and the nonenergy-related subsidiaries of Yankee (Yankee Energy Services Company), Yankee Energy Financial Services Company, and NorConn Properties, Inc.)

PSNH

Public Service Company of New Hampshire

Regulated companies

NU's regulated companies, comprised of the electric distribution and transmission segments of CL&P, PSNH, WMECO, the generation segment of PSNH, a natural gas local distribution company, and Yankee Gas.  For further information, see Note 10, "Segment Information," to the condensed consolidated financial statements.

SECI

Select Energy Contracting, Inc.

Select Energy

Select Energy, Inc.

SESI

Select Energy Services, Inc.

WMECO

Western Massachusetts Electric Company

Yankee

Yankee Energy System, Inc.

Yankee Gas

Yankee Gas Services Company

 

 

REGULATORS:

 

 

 

DPU

Massachusetts Department of Public Utilities (formerly the Massachusetts Department of Telecommunications and Energy (DTE))

DPUC

Connecticut Department of Public Utility Control

FERC

Federal Energy Regulatory Commission

NHPUC

New Hampshire Public Utilities Commission

SEC

Securities and Exchange Commission




i





OTHER: 

 

 

 

AFUDC

Allowance For Funds Used During Construction

CfD

Contract for Differences

CTA

Competitive Transition Assessment

EPS

Earnings Per Share

ES

Default Energy Service

FASB

Financial Accounting Standards Board

FMCC

Federally Mandated Congestion Charges

GSC

Generation Service Charge

ISO-NE

New England Independent System Operator or ISO New England, Inc.

KWH

Kilowatt-Hour

KV

Kilovolt

LOC

Letter of Credit

MW

Megawatts

NU 2007 Form 10-K

The Northeast Utilities and Subsidiaries combined 2007 Annual Report on Form 10-K as filed with the SEC

NYMPA

New York Municipal Power Agency

PBOP

Postretirement Benefits Other Than Pensions

Regulatory ROE

The average cost of capital method for calculating the return on equity related to the distribution and generation business segments excluding the wholesale transmission segment.

RMR

Reliability Must Run

ROE

Return on Equity

SBC

System Benefits Charge

SCRC

Stranded Cost Recovery Charge

SFAS

Statement of Financial Accounting Standards

TCAM

Transmission Cost Adjustment Mechanism

TSO

Transitional Standard Offer

UI

The United Illuminating Company

VAR

Voltage Ampere Reactive




ii




NORTHEAST UTILITIES AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

TABLE OF CONTENTS



 

Page

 

 

PART I - FINANCIAL INFORMATION

 

 

ITEM 1 - Condensed Consolidated Financial Statements for the Following Companies:

 

 

 

Northeast Utilities and Subsidiaries

 

 

Condensed Consolidated Balance Sheets (Unaudited) - June 30, 2008 and December 31, 2007

2

 

Condensed Consolidated Statements of Income (Unaudited) - Three and Six Months Ended June 30, 2008 and 2007

4

 

Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2008 and 2007

5

 

Notes to Condensed Consolidated Financial Statements (Unaudited - all companies)

6

 

Report of Independent Registered Public Accounting Firm

31

 

The Connecticut Light and Power Company and Subsidiaries

 

 

Condensed Consolidated Balance Sheets (Unaudited) - June 30, 2008 and December 31, 2007

34

 

Condensed Consolidated Statements of Income (Unaudited) - Three and Six Months Ended June 30, 2008 and 2007

36

 

Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2008 and 2007

37

 

Public Service Company of New Hampshire and Subsidiaries

 

 

Condensed Consolidated Balance Sheets (Unaudited) - June 30, 2008 and December 31, 2007

40

 

Condensed Consolidated Statements of Income (Unaudited) - Three and Six Months Ended June 30, 2008 and 2007

42

 

Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2008 and 2007

43

 

Western Massachusetts Electric Company and Subsidiary

 

 

Condensed Consolidated Balance Sheets (Unaudited) - June 30, 2008 and December 31, 2007

46

 

Condensed Consolidated Statements of Income (Unaudited) - Three and Six Months Ended June 30, 2008 and 2007

48

 

Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2008 and 2007

49

 




iii





 

Page

 

 

ITEM 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations for the following  companies:

 

 

Northeast Utilities and Subsidiaries

50

 

The Connecticut Light and Power Company and Subsidiaries

75

 

Public Service Company of New Hampshire and Subsidiaries

79

 

Western Massachusetts Electric Company and Subsidiary

82

 

ITEM 3 - Quantitative and Qualitative Disclosures About Market Risk

85

 

 

ITEM 4 - Controls and Procedures

86

 

PART II - OTHER INFORMATION

 

ITEM 1 - Legal Proceedings

87

 

ITEM 1A - Risk Factors

87

 

ITEM 2 - Unregistered Sales of Equity Securities and Use of Proceeds

87

 

 

ITEM 4 - Submission of Matters to a Vote of Security Holders

87

 

ITEM 6 - Exhibits

89

 

SIGNATURES

91

 





iv




NORTHEAST UTILITIES AND SUBSIDIARIES



1





NORTHEAST UTILITIES AND SUBSIDIARIES

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

(Unaudited)

 

 

 

 

June 30,

 

December 31,

 

2008

 

2007

 

(Thousands of Dollars)

ASSETS

 

 

 

 

 

 

 

Current Assets:

 

 

 

  Cash and cash equivalents

$                12,128 

 

$                15,104 

  Investments in securitizable assets (Note 1E)

 

308,182 

  Receivables, less provision for uncollectible

 

 

 

    accounts of $41,863 in 2008 and $25,529 in 2007

584,494 

 

401,283 

  Unbilled revenues

195,414 

 

101,860 

  Taxes receivable

75,574 

 

13,850 

  Fuel, materials and supplies

228,767 

 

210,850 

  Marketable securities - current

82,488 

 

70,816 

  Derivative assets - current

177,793 

 

105,517 

  Prepayments and other

37,028 

 

58,794 

 

1,393,686 

 

1,286,256 

 

 

 

 

Property, Plant and Equipment:

 

 

 

  Electric utility

8,027,373 

 

7,594,606 

  Gas utility

1,003,459 

 

977,290 

  Other

287,391 

 

310,535 

 

9,318,223 

 

8,882,431 

    Less: Accumulated depreciation: $2,559,324 for electric

 

 

 

               and gas utility and $158,305 for other in 2008;

 

 

 

               $2,483,570 for electric and gas utility and

 

 

 

               $178,193 for other in 2007

2,717,629 

 

2,661,763 

 

6,600,594 

 

6,220,668 

  Construction work in progress

1,121,154 

 

1,009,277 

 

7,721,748 

 

7,229,945 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

  Regulatory assets

2,449,551 

 

2,057,083 

  Goodwill

287,591 

 

287,591 

  Prepaid pension

219,431 

 

202,512 

  Marketable securities - long-term

38,625 

 

53,281 

  Derivative assets - long-term

446,631 

 

298,001 

  Other

151,989 

 

167,153 

 

3,593,818 

 

3,065,621 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

$         12,709,252 

 

$         11,581,822 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 




2





NORTHEAST UTILITIES AND SUBSIDIARIES

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

(Unaudited)

 

 

 

 

June 30,

 

December 31,

 

2008

 

2007

 

(Thousands of Dollars)

LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

  Notes payable to banks

$                 87,000 

 

$                 79,000 

  Long-term debt - current portion

54,286 

 

154,286 

  Accounts payable

568,774 

 

598,546 

  Accrued interest

61,786 

 

56,592 

  Derivative liabilities - current

35,898 

 

71,601 

  Other

304,795 

 

246,125 

 

1,112,539 

 

1,206,150 

 

 

 

 

Rate Reduction Bonds

802,259 

 

917,436 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

  Accumulated deferred income taxes

1,109,783 

 

1,067,490 

  Accumulated deferred investment tax credits

27,108 

 

28,845 

  Deferred contractual obligations

205,935 

 

222,908 

  Regulatory liabilities

897,282 

 

851,780 

  Derivative liabilities - long-term

811,147 

 

208,461 

  Accrued postretirement benefits

170,641 

 

181,507 

  Other

426,614 

 

383,611 

 

3,648,510 

 

2,944,602 

 

 

 

 

Capitalization:

 

 

 

  Long-Term Debt

4,090,288 

 

3,483,599 

 

 

 

 

  Preferred Stock of Subsidiary - Non-Redeemable

116,200 

 

116,200 

 

 

 

 

  Common Shareholders' Equity:

 

 

 

    Common shares, $5 par value - authorized

 

 

 

      225,000,000 shares; 176,160,857 shares issued

 

 

 

      and 155,523,764 shares outstanding in 2008 and

 

 

 

      175,924,694 shares issued and 155,079,770 shares

 

 

 

      outstanding in 2007

880,804 

 

879,623 

    Capital surplus, paid in

1,469,588 

 

1,465,946 

    Deferred contribution plan - employee stock

 

 

 

      ownership plan

(21,481)

 

(26,352)

    Retained earnings

967,329 

 

946,792 

    Accumulated other comprehensive income

4,819 

 

9,359 

    Treasury stock, 19,708,136 shares in 2008

 

 

 

      and 19,705,545 shares in 2007

(361,603)

 

(361,533)

  Common Shareholders' Equity

2,939,456 

 

2,913,835 

Total Capitalization

7,145,944 

 

6,513,634 

 

 

 

 

Commitments and Contingencies (Note 5)

 

 

 

 

 

 

 

Total Liabilities and Capitalization

$          12,709,252 

 

$          11,581,822 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements. 

 

 

 

 

 

 




3





NORTHEAST UTILITIES AND SUBSIDIARIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

 

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2008

 

2007

 

2008

 

2007

 

(Thousands of Dollars, except share information)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$   1,325,345 

 

$   1,391,772 

 

$   2,845,312 

 

$   3,095,290 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

  Operation -

 

 

 

 

 

 

 

     Fuel, purchased and net interchange power

661,699 

 

804,802 

 

1,485,016 

 

1,875,288 

     Other

237,203 

 

245,879 

 

523,084 

 

483,112 

  Maintenance

70,896 

 

59,842 

 

127,605 

 

105,827 

  Depreciation

68,321 

 

63,420 

 

136,075 

 

126,889 

  Amortization of regulatory assets/(liabilities), net

41,945 

 

(3,453)

 

70,800 

 

2,770 

  Amortization of rate reduction bonds

47,884 

 

47,114 

 

101,234 

 

98,913 

  Taxes other than income taxes

59,278 

 

57,360 

 

131,107 

 

129,950 

       Total operating expenses

1,187,226 

 

1,274,964 

 

2,574,921 

 

2,822,749 

Operating Income

138,119 

 

116,808 

 

270,391 

 

272,541 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

  Interest on long-term debt

46,449 

 

40,234 

 

89,222 

 

76,447 

  Interest on rate reduction bonds

12,987 

 

15,839 

 

26,703 

 

32,189 

  Other interest

6,624 

 

3,504 

 

12,776 

 

10,223 

       Interest expense, net

66,060 

 

59,577 

 

128,701 

 

118,859 

Other Income, Net

10,370 

 

11,873 

 

23,928 

 

25,942 

Income from Continuing Operations Before

 

 

 

 

 

 

 

  Income Tax Expense

82,429 

 

69,104 

 

165,618 

 

179,624 

Income Tax Expense

23,192 

 

21,703 

 

46,598 

 

54,426 

Income from Continuing Operations Before

 

 

 

 

 

 

 

  Preferred Dividends of Subsidiary

59,237 

 

47,401 

 

119,020 

 

125,198 

Preferred Dividends of Subsidiary

1,389 

 

1,389 

 

2,779 

 

2,779 

Income from Continuing Operations

57,848 

 

46,012 

 

116,241 

 

122,419 

Discontinued Operations:

 

 

 

 

 

 

 

  Income from Discontinued Operations

 

564 

 

 

248 

  Gains from Sale/Disposition of Discontinued Operations

 

3,925 

 

 

2,017 

  Income Tax Expense

 

1,948 

 

 

1,037 

Income from Discontinued Operations

 

2,541 

 

 

1,228 

Net Income

$        57,848 

 

$        48,553 

 

$      116,241 

 

$      123,647 

 

 

 

 

 

 

 

 

Basic and Fully Diluted Earnings Per Common Share:

 

 

 

 

 

 

 

  Income from Continuing Operations

$            0.37 

 

$            0.30 

 

$            0.75 

 

$            0.79 

  Income from Discontinued Operations

 

0.01 

 

 

0.01 

Basic and Fully Diluted Earnings Per Common Share

$            0.37 

 

$            0.31 

 

$            0.75 

 

$            0.80 

 

 

 

 

 

 

 

 

Basic Common Shares Outstanding (weighted average)

155,476,492 

 

154,729,676 

 

155,381,302 

 

154,539,678 

 

 

 

 

 

 

 

 

Fully Diluted Common Shares Outstanding (weighted average)

155,895,348 

 

155,213,094 

 

155,808,481 

 

155,102,672 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 

 

 

 

 

 

 



4





NORTHEAST UTILITIES AND SUBSIDIARIES

 

 

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

 

 

 

(Unaudited)

 

Six Months Ended

 

 

June 30,

 

 

2008

 

 

2007

 

 

(Thousands of Dollars)

 

 

 

Operating Activities:

 

 

 

 

 

Net income

$

116,241 

 

$

123,647 

Adjustments to reconcile to net cash flows

 

 

 

 

 

  provided by/(used in) operating activities:

 

 

 

 

 

Bad debt expense

 

13,163 

 

 

12,917 

Depreciation

 

136,075 

 

 

126,889 

Deferred income taxes

 

52,995 

 

 

 (10,158)

Pension expense, net of capitalized portion

 

4,011 

 

 

10,388 

(Deferral)/amortization of recoverable energy costs

 

 (6,046)

 

 

6,248 

Amortization of rate reduction bonds

 

101,234 

 

 

98,913 

Amortization of regulatory assets, net

 

70,800 

 

 

2,770 

Regulatory (refunds and underrecoveries)/overrecoveries

 

 (128,830)

 

 

64,174 

Derivative assets and liabilities

 

 (25,216)

 

 

 (36,830)

Deferred contractual obligations

 

 (16,973)

 

 

 (23,489)

Other non-cash adjustments

 

 (7,165)

 

 

 (2,989)

Other sources of cash

 

274 

 

 

Other uses of cash

 

 (15,552)

 

 

 (35,019)

Changes in current assets and liabilities:

 

 

 

 

 

Receivables and unbilled revenues, net

 

35,760 

 

 

56,248 

Fuel, materials and supplies

 

 (17,946)

 

 

 (12,135)

Investments in securitizable assets

 

 (25,787)

 

 

17,674 

Other current assets

 

6,426 

 

 

7,177 

Accounts payable

 

 (20,648)

 

 

 (67,312)

Counterparty deposits and margin special deposits

 

59,110 

 

 

18,926 

Taxes receivable/accrued

 

 (31,412)

 

 

 (372,867)

Other current liabilities

 

 (21,489)

 

 

 (22,672)

Net cash flows provided by/(used in) operating activities

 

279,025 

 

 

 (37,500)

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

Investments in property and plant

 

 (625,133)

 

 

 (491,137)

Proceeds from sales of investment securities

 

128,778 

 

 

101,113 

Purchases of investment securities

 

 (130,105)

 

 

 (103,902)

Rate reduction bond escrow and other deposits

 

9,010 

 

 

8,567 

Other investing activities

 

2,385 

 

 

42 

Net cash flows used in investing activities

 

 (615,065)

 

 

 (485,317)

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

Issuance of common shares

 

4,562 

 

 

8,520 

Issuance of long-term debt

 

660,000 

 

 

345,000 

Retirements of rate reduction bonds

 

 (115,177)

 

 

 (109,755)

Increase in short-term debt

 

8,000 

 

 

Retirements of long-term debt

 

 (154,286)

 

 

 (4,877)

Cash dividends on common shares

 

 (62,574)

 

 

 (58,502)

Other financing activities

 

 (7,461)

 

 

 (657)

Net cash flows provided by financing activities

 

333,064 

 

 

179,729 

Net decrease in cash and cash equivalents

 

 (2,976)

 

 

 (343,088)

Cash and cash equivalents - beginning of period

 

15,104 

 

 

481,911 

Cash and cash equivalents - end of period

$

12,128 

 

$

138,823 

 

 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 

 

 

 

 

 

 

 




5




NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)



1.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)


A.

Presentation


Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (SEC).  The accompanying unaudited condensed consolidated financial statements should be read in conjunction with the entirety of this Quarterly Report on Form 10-Q, the first quarter 2008 Quarterly Report on Form 10-Q and the Annual Reports of Northeast Utilities (NU or the company), The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), which were filed with the SEC as part of the Northeast Utilities and subsidiaries combined 2007 Annual Report on Form 10-K (NU 2007 Form 10-K).  The accompanying condensed consolidated financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU's and the above companies' financial position at June 30, 2008 and December 31, 2007, the results of operations for the three and six months ended June 30, 2008 and 2007 and cash flows for the six months ended June 30, 2008 and 2007.  The results of operations and cash flows for the six months ended June 30, 2008 and 2007 are not necessarily indicative of the results expected for a full year.  


The condensed consolidated financial statements of NU and its subsidiaries, as applicable, include the accounts of all their respective subsidiaries.  Intercompany transactions have been eliminated in consolidation.


The preparation of condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.


Certain reclassifications of prior period data included in the accompanying condensed consolidated financial statements have been made to conform with the current period's presentation.


NU's condensed consolidated statements of income for the three and six months ended June 30, 2007 classify activity related to the following subsidiaries as discontinued operations:


·

Northeast Generation Company (NGC),

·

The Mt. Tom generating plant (Mt. Tom) previously owned by Holyoke Water Power Company (HWP), and

·

Select Energy Contracting, Inc. (including Reeds Ferry Supply Co., Inc.) (SECI).  


For the three and six months ended June 30, 2007, portions of SECI that were included in continuing operations have been reclassified to discontinued operations in the condensed consolidated statements of income as a result of winding down SECI operations in 2007.  The amounts of these reclassifications are as follows:



(Millions of Dollars)

 

Three Months Ended

June 30, 2007

 

Six Months Ended

June 30, 2007

Operating revenues

 

$

0.3 

 

$

1.1 

Operating benefits/(expenses)

 

 

0.2 

 

 

(0.9)

Income from discontinued operations  

 

 

0.5 

 

 

0.2 

Income tax expense from discontinued operations

 

 

(0.4)

 

 

(0.2)

Net income from discontinued operations

 

 

0.1 

 

 


For further information regarding discontinued operations, see Note 7, "Discontinued Operations," to the condensed consolidated financial statements.  




6




B.

Regulatory Accounting


The accounting policies of the regulated companies conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation."


The transmission and distribution segments of CL&P, PSNH and WMECO, along with PSNH's generation segment and Yankee Gas Service Company's (Yankee Gas) distribution segment, continue to be cost-of-service, rate regulated.  Management believes that the application of SFAS No. 71 to those segments continues to be appropriate.  Management also believes it is probable that NU's regulated companies will recover their investments in long-lived assets, including regulatory assets.  All material net regulatory assets are earning an equity return, except for securitized regulatory assets and the majority of deferred benefit costs, which are not supported by equity.  Amortization and deferrals of regulatory assets/(liabilities) are included on a net basis in amortization expense on the accompanying condensed consolidated statements of income.  


Regulatory Assets:  The components of regulatory assets are as follows:  


 

 

At June 30, 2008


(Millions of Dollars)

 

NU
Consolidated

 


CL&P

 


PSNH

 


WMECO

 

Yankee Gas
and Other

Securitized assets

 

$

793.6 

 

$

464.3 

 

$

250.5 

 

$

78.8 

 

$

Income taxes, net

 

 

351.3 

 

 

298.0 

 

 

10.1 

 

 

34.1 

 

 

9.1 

Deferred benefit costs

 

 

171.7 

 

 

60.9 

 

 

45.6 

 

 

6.3 

 

 

58.9 

Unrecovered contractual obligations

 

 

179.1 

 

 

140.2 

 

 

 

 

38.9 

 

 

Regulatory assets offsetting regulated
  company derivative liabilities

 

 


629.2 

 

 


629.1 

 

 


 

 


 

 


0.1 

CL&P CTA and SBC undercollections

 

 

50.2 

 

 

50.2 

 

 

 

 

 

 

Other regulatory assets

 

 

274.5 

 

 

135.7 

 

 

67.9 

 

 

15.8 

 

 

55.1 

Totals

 

$

2,449.6 

 

$

1,778.4 

 

$

374.1 

 

$

173.9 

 

$

123.2 


 

 

At December 31, 2007


(Millions of Dollars)

 

NU
Consolidated

 


CL&P

 


PSNH

 


WMECO

 

Yankee Gas
and Other

Securitized assets

 

$

907.0 

 

$

548.2 

 

$

273.2 

 

$

85.6 

 

$

Income taxes, net

 

 

335.5 

 

 

279.4 

 

 

10.3 

 

 

38.2 

 

 

7.6 

Deferred benefit costs

 

 

201.4 

 

 

72.2 

 

 

50.4 

 

 

8.2 

 

 

70.6 

Unrecovered contractual obligations

 

 

189.9 

 

 

148.0 

 

 

 

 

42.0 

 

 

(0.1)

Regulatory assets offsetting regulated
  company derivative liabilities

 

 


122.3 

 

 


119.8 

 

 


2.5 

 

 


 

 


CL&P CTA and SBC undercollections

 

 

90.6 

 

 

90.6 

 

 

 

 

 

 

Other regulatory assets

 

 

210.4 

 

 

71.8 

 

 

65.0 

 

 

19.9 

 

 

53.7 

Totals

 

$

2,057.1 

 

$

1,330.0 

 

$

401.4 

 

$

193.9 

 

$

131.8 


For information regarding regulatory assets offsetting regulated company derivative liabilities, see Note 2, "Derivative Instruments," to the condensed consolidated financial statements.  


Included in NU's other regulatory assets are the regulatory assets associated with the implementation of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $43 million at June 30, 2008 and $40.6 million at December 31, 2007.  Management believes that recovery of these regulatory assets is probable.  


Additionally, the regulated companies had $2.8 million and $11.9 million of regulatory costs at June 30, 2008 and December 31, 2007, respectively, that were included in deferred debits and other assets - other on the accompanying condensed consolidated balance sheets.  These amounts represent regulatory costs that have not yet been approved for recovery by the applicable regulatory agency.  Management believes these costs are recoverable in future cost-of-service regulated rates.




7




Regulatory Liabilities:  The components of regulatory liabilities are as follows:  


 

 

At June 30, 2008


(Millions of Dollars)

 

NU
Consolidated

 


CL&P

 


PSNH

 


WMECO

 


Yankee Gas

Cost of removal

 

$

237.1 

 

$

97.3 

 

$

67.7 

 

$

20.8 

 

$

51.3 

Regulatory liabilities offsetting
  regulated company derivative assets

 

 


478.6 

 

 


384.2 

 

 


92.7 

 

 


 

 


1.7 

CL&P GSC and FMCC overcollections

 

 

45.1 

 

 

45.1 

 

 

 

 

 

 

Other regulatory liabilities

 

 

136.5 

 

 

73.2 

 

 

25.0 

 

 

15.6 

 

 

22.7 

Totals

 

$

897.3 

 

$

599.8 

 

$

185.4 

 

$

36.4 

 

$

75.7 


 

 

At December 31, 2007


(Millions of Dollars)

 

NU
Consolidated

 


CL&P

 


PSNH

 


WMECO

 


Yankee Gas

Cost of removal

 

$

262.6 

 

$

116.6 

 

$

72.8 

 

$

21.5 

 

$

51.7 

Regulatory liabilities offsetting
  regulated company derivative assets

 

 


330.4 

 

 


313.0 

 

 


17.2 

 

 


 

 


0.2 

CL&P GSC and FMCC overcollections

 

 

119.2 

 

 

119.2 

 

 

 

 

 

 

Other regulatory liabilities

 

 

139.6 

 

 

52.7 

 

 

37.6 

 

 

17.9 

 

 

31.4 

Totals

 

$

851.8 

 

$

601.5 

 

$

127.6 

 

$

39.4 

 

$

83.3 


For information regarding regulatory liabilities offsetting regulated company derivative assets, see Note 2, "Derivative Instruments," to the condensed consolidated financial statements.


C.

Fair Value Measurements


On January 1, 2008, the company adopted SFAS No. 157, "Fair Value Measurements," which establishes a framework for defining and measuring fair value and requires expanded disclosures about fair value measurements.  SFAS No. 157:


·

Defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price).


·

Establishes a three-level fair value hierarchy based upon the observability of inputs to the valuations of assets and liabilities.


·

Requires consideration of the company's own creditworthiness and risk of nonperformance when valuing its liabilities.


·

Requires prospective implementation with adjustments to fair value reflected in earnings, similar to a change in estimate, with exceptions including recognition of previously deferred initial gains or losses described below.  


·

Requires recognition in retained earnings of previously deferred initial gains or losses on derivative contracts whose estimated fair values are based on significant unobservable inputs.  Recognition of the initial gains or losses was previously prohibited under Emerging Issues Task Force Issue No. 02-3, " Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities."  CL&P’s initial gains and losses on its contracts for differences (CfDs) that would have been recorded in retained earnings upon adoption were recorded as regulatory assets and liabilities because their costs or benefits are expected to be fully recovered from or refunded to customers.  

  

The company applied SFAS No. 157 to the regulated and unregulated companies' derivative contracts that are recorded at fair value and to the marketable securities held in NU's Rabbi Trust and WMECO's prior spent nuclear fuel trust.  SFAS No. 157 also applies to investment valuations for NU’s pension and other postretirement benefit plans beginning as of December 31, 2008, and beginning in 2009, to nonrecurring fair value measurements of non-financial assets and liabilities such as goodwill and asset retirement obligations.


As a result of adopting SFAS No. 157, the company recorded a pre-tax charge to earnings of $6.1 million as of January 1, 2008 related to derivative liabilities for its remaining unregulated wholesale marketing contracts.  For the three and six months ended June 30, 2008, the company recorded a $1 million and $2.2 million pre-tax benefit, respectively, to partially reverse the exit price impact recorded under SFAS No. 157 as the company served out rather than exited the contracts.  


The company also recorded changes in fair value of certain derivative contracts of CL&P.  Because CL&P is a cost-of-service, rate regulated entity, the cost or benefit of the contracts is expected to be fully recovered from or refunded to CL&P's customers and an offsetting regulatory asset or liability was recorded to reflect these changes.  As of January 1, 2008, implementing SFAS No. 157



8




resulted in a total increase to CL&P's derivative liabilities, with an offset to regulatory assets, of approximately $590 million, and a total decrease to derivative assets, with an offset to regulatory liabilities, of approximately $30 million.


Fair Value Hierarchy:  As required by SFAS No. 157, in measuring fair value the company uses observable market data when available and minimizes the use of unobservable inputs.  Unobservable inputs are needed to value certain derivative contracts due to complexities in contractual terms and the long duration of a contract.  SFAS No. 157 requires inputs used in fair value measurements to be categorized into three fair value hierarchy levels for disclosure purposes.  The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement.  


The three levels of the fair value hierarchy are described below:


Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  


Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.


Level 3 - Quoted market prices are not available.  Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable.  Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products.  Significant unobservable inputs are used in the valuations, including items such as energy and energy-related product prices in future years for which observable prices are not yet available, future contract quantities under full-requirements or supplemental sales contracts, and market volatilities.  Items valued using these valuation techniques are classified according to the lowest level for which there is at least one input that is significant to the valuation.  Therefore, an item may be classified in Level 3 even though there may be some significant inputs that are readily observable.   


Determination of Fair Value:  The following is a description of the valuation techniques utilized in our fair value measurements:


Derivative contracts:   Many of the company's derivative positions that are recorded at fair value are classified as Level 3 within the fair value hierarchy and are valued using models that incorporate both observable and unobservable inputs.  Fair value is modeled using techniques such as discounted cash flow approaches adjusted for assumptions relating to exit price and the Black-Scholes option pricing model, incorporating the terms of the contracts.  Significant unobservable inputs utilized in the valuations include energy and energy-related product prices for future years for long-dated derivative contracts, future contract quantities under full requirements and supplemental sales contracts, and market volatilities.  Discounted cash flow valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using available historical market transaction information.  Valuations of derivative contracts also reflect nonperformance risk, including credit.  The derivative contracts classified as Level 3 include NU Enterprises, Inc.'s (NU Enterprises) remaining wholesale marketing contract and its related supply contracts, CL&P's CfDs, CL&P's contracts with certain independent power producers (IPPs) and regulated company options and financial transmission rights (FTRs).


Other derivative contracts recorded at fair value are classified as Level 2 within the fair value hierarchy.  An active market for the same or similar contracts exists for these contracts, which include regulated company forward contracts to purchase energy and interest rate swap agreements for the regulated companies and NU parent.  For these contracts, valuations are based on quoted prices in the market and include some modeling using market-based assumptions.  


For further information on derivative contracts, see Note 2, "Derivative Instruments," to the condensed consolidated financial statements.


Marketable securities:  The company holds in trust marketable securities, which include equity securities, mutual funds and cash equivalents, and fixed maturity securities.


Equity securities, mutual funds and cash equivalents are classified as Level 1 in the fair value hierarchy.  These investments are traded in active markets and quoted prices are available for identical investments.


Fixed maturity securities classified as Level 2 within the fair value hierarchy include U.S. Treasury securities, corporate bonds, collateralized mortgage obligations, U.S. pass-through bonds, asset-backed securities, commercial mortgage-backed securities, and commercial paper.  The fair value of these instruments is estimated using pricing models, quoted prices of securities with similar characteristics or discounted cash flows.  The pricing models utilize observable inputs such as recent trades for the same or similar instruments, yield curves, discount margins and bond structures.  



9





For further information see Note 3, "Fair Value Measurements," to the accompanying condensed consolidated financial statements.


D.

Allowance for Funds Used During Construction


The allowance for funds used during construction (AFUDC) is included in the cost of the regulated companies' utility plant and represents the cost of borrowed and equity funds used to finance construction.  The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense, and the AFUDC related to equity funds is recorded as other income on the accompanying condensed consolidated statements of income:


 

For the Three Months Ended

 

For the Six Months Ended

(Millions of Dollars, except percentages)

June 30, 2008

 

June 30, 2007

 

June 30, 2008

 

June 30, 2007

Borrowed funds

$

4.4    

 

$

4.3    

 

$

9.1    

 

$

8.6    

Equity funds

 

6.8    

 

 

4.0    

 

 

15.1    

 

 

6.3    

Totals

$

11.2    

 

$

8.3    

 

$

24.2    

 

$

14.9    

Average AFUDC rates

 

7.9% 

 

 

7.5% 

 

 

8.1% 

 

 

7.2% 


The regulated companies' average AFUDC rate is based on a Federal Energy Regulatory Commission (FERC) prescribed formula that produces an average rate using the cost of a company's short-term financings as well as a company's capitalization (preferred stock, long-term debt and common equity).  The average rate is applied to eligible construction work in progress (CWIP) amounts to calculate AFUDC.  Although AFUDC is recorded on 100 percent of CL&P's CWIP for its major transmission projects in southwest Connecticut, 50 percent of this AFUDC is being reserved as a regulatory liability to reflect current rate base recovery for 50 percent of the CWIP as a result of FERC approved transmission incentives.


E.

Sale of Customer Receivables


Prior to June 30, 2008, under the Receivables Purchase and Sale Agreement, CL&P Receivables Corporation (CRC), a consolidated, wholly-owned subsidiary of CL&P, purchased an undivided interest in CL&P's accounts receivable and unbilled revenues and could sell up to $100 million thereof to a financial institution.  At December 31, 2007, there were $20 million in such sales.  On June 30, 2008, there were no receivables sold under that facility, and CL&P chose to terminate the Receivables Purchase and Sale Agreement.   


At December 31, 2007, amounts totaling $308.2 million sold to CRC by CL&P but not sold to the financial institution were included in investments in securitizable assets on the accompanying condensed consolidated balance sheet.  These amounts would have been excluded from CL&P's assets in the event of bankruptcy by CL&P.  As of June 30, 2008, these amounts were no longer excludable from CL&P's assets in the event of bankruptcy and were no longer securitizable.  Since CL&P chose to terminate the Receivables Purchase and Sale Agreement at June 30, 2008, amounts held by CRC were included in accounts receivables and unbilled revenues on the accompanying condensed consolidated balance sheet.  


F.

Cash and Cash Equivalents


Cash and cash equivalents include cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less.  At the end of each reporting period, any overdraft amounts are reclassified from cash and cash equivalents to accounts payable.


G.

Special Deposits and Counterparty Deposits


To the extent Select Energy, Inc. (Select Energy) requires collateral from counterparties, or the counterparties require collateral from Select Energy, cash held on deposit by Select Energy or with unaffiliated counterparties and brokerage firms as a part of the total collateral required based on Select Energy’s position in the transaction.  Select Energy's right to use cash collateral is determined by the terms of the related agreements.  Key factors affecting the unrestricted status of a portion of this cash collateral include the financial standing of Select Energy and of NU as its credit supporter.  


Special deposits paid to unaffiliated counterparties and brokerage firms totaled $18.9 million at December 31, 2007.  There were no special deposits as of June 30, 2008.  These amounts are recorded as current assets and are included in prepayments and other on the accompanying condensed consolidated balance sheets.  Balances collected from counterparties resulting from Select Energy’s credit management activities totaled $6.4 million at June 30, 2008.  There were no counterparty deposits for Select Energy as of December 31, 2007.  These amounts are recorded as current liabilities and are included in other current liabilities on the accompanying condensed consolidated balance sheets.  




10




CL&P and WMECO had $24.8 million and $9 million, respectively, of counterparty deposits at June 30, 2008 related to credit management activities.  These amounts were recorded as current liabilities - other on the accompanying condensed consolidated balance sheets.  There were no counterparty deposits for these companies as of December 31, 2007.


NU also had amounts on deposit related to special purpose entities used to facilitate the issuance of rate reduction bonds and certificates.  These amounts totaled $34.5 million and $43.5 million at June 30, 2008 and December 31, 2007, respectively.  These amounts totaled $8.9 million and $14.3 million for CL&P, $21.2 million and $24.4 million for PSNH, and $4.4 million and $4.8 million for WMECO at June 30, 2008 and December 31, 2007, respectively.  In addition, the company had $6.5 million and $6.4 million in other cash deposits held with unaffiliated parties at June 30, 2008 and December 31, 2007, respectively, primarily related to CL&P's transmission projects.  These amounts were included in deferred debits and other assets - other on the accompanying condensed consolidated balance sheets.


H.

Other Income, Net


The pre-tax components of other income/(loss) items are as follows:


NU

 

For the Three Months Ended

 

For the Six Months Ended

(Millions of Dollars)

 

June 30, 2008

 

June 30, 2007

 

June 30, 2008

 

June 30, 2007

Other Income:  

 

 

 

 

 

 

 

 

 

 

 

 

  Investment income

 

$

2.0 

 

$

5.9 

 

$

3.9 

 

$

14.4 

  AFUDC - equity funds

 

 

6.8 

 

 

4.0 

 

 

15.1 

 

 

6.3 

  Energy Independence Act incentives

 

 

3.4 

 

 

2.2 

 

 

8.9 

 

 

4.9 

  Other

 

 

0.2 

 

 

0.4 

 

 

0.4 

 

 

0.9 

Total Other Income

 

 

12.4 

 

 

12.5 

 

 

28.3 

 

 

26.5 

Other Loss:

 

 

 

 

 

 

 

 

 

 

 

 

  Investment loss

 

 

(1.2)

 

 

 

 

(3.8)

 

 

  Investment write-down

 

 

 

 

(0.5)

 

 

 

 

(0.5)

  Other

 

 

(0.8)

 

 

(0.1)

 

 

(0.6)

 

 

(0.1)

Total Other Loss

 

 

(2.0)

 

 

(0.6)

 

 

(4.4)

 

 

(0.6)

Total Other Income, Net

 

$

10.4 

 

$

11.9 

 

$

23.9 

 

$

25.9 


CL&P

 

For the Three Months Ended

 

For the Six Months Ended

(Millions of Dollars)

 

June 30, 2008

 

June 30, 2007

 

June 30, 2008

 

June 30, 2007

Other Income:  

 

 

 

 

 

 

 

 

 

 

 

 

  Investment income

 

$

1.9 

 

$

1.6 

 

$

3.3 

 

$

3.0 

  AFUDC - equity funds

 

 

5.8 

 

 

2.9 

 

 

12.4 

 

 

4.4 

  Energy Independence Act incentives

 

 

3.4 

 

 

2.2 

 

 

8.9 

 

 

4.9 

  Other

 

 

0.2 

 

 

0.2 

 

 

0.3 

 

 

0.5 

Total Other Income

 

 

11.3 

 

 

6.9 

 

 

24.9 

 

 

12.8 

Other Loss:

 

 

 

 

 

 

 

 

 

 

 

 

  Investment loss

 

 

(0.8)

 

 

 

 

 (2.6)

 

 

-

  Other

 

 

 (0.9)

 

 

 

 

(0.6)

 

 

(0.1)

Total Other Loss

 

 

(1.7)

 

 

 

 

(3.2)

 

 

(0.1)

Total Other Income, Net

 

$

9.6 

 

$

6.9 

 

$

21.7 

 

$

12.7 


PSNH

 

For the Three Months Ended

 

For the Six Months Ended

(Millions of Dollars)

 

June 30, 2008

 

June 30, 2007

 

June 30, 2008

 

June 30, 2007

Other Income:  

 

 

 

 

 

 

 

 

 

 

 

 

  Investment income

 

$

0.6 

 

$

0.2 

 

$

0.9 

 

$

0.4 

  AFUDC - equity funds

 

 

0.9 

 

 

0.5 

 

 

2.2 

 

 

0.9 

  Other

 

 

 

 

 

 

0.1 

 

 

0.1 

Total Other Income

 

 

1.5 

 

 

0.7 

 

 

3.2 

 

 

1.4 

Investment loss

 

 

(0.2)

 

 

 

 

(0.6)

 

 

Total Other Income, Net

 

$

1.3 

 

$

0.7 

 

$

2.6 

 

$

1.4 




11





WMECO

 

For the Three Months Ended

 

For the Six Months Ended

(Millions of Dollars)

 

June 30, 2008

 

June 30, 2007

 

June 30, 2008

 

June 30, 2007

Other Income:  

 

 

 

 

 

 

 

 

 

 

 

 

  Investment income

 

$

0.4 

 

$

0.3 

 

$

0.6 

 

$

0.6 

  AFUDC - equity funds

 

 

0.2 

 

 

 

 

0.4 

 

 

  Conservation and load management incentive

 

 

0.1 

 

 

0.1 

 

 

0.2 

 

 

0.3 

Total Other Income

 

 

0.7 

 

 

0.4 

 

 

1.2 

 

 

0.9 

Investment loss

 

 

(0.2)

 

 

 

 

(0.5)

 

 

Total Other Income, Net

 

$

0.5 

 

$

0.4 

 

$

0.7 

 

$

0.9 


Investment income for NU includes equity in earnings of regional nuclear generating and transmission companies of $0.3 million and $0.4 million for the three months ended June 30, 2008 and 2007, respectively, and $1 million and $1.1 million for the six months ended June 30, 2008 and 2007, respectively.  Equity in earnings relates to the company's investment in Connecticut Yankee Atomic Power Company (CYAPC), Maine Yankee Atomic Power Company, Yankee Atomic Electric Company and two regional transmission companies.


I.

Income Taxes


Tax Positions:   NU is currently working to resolve all open tax years.  It is reasonably possible that one or more of these open tax years could be resolved within the next twelve months.  NU has significantly advanced settlement positions with the Internal Revenue Service related to the timing of deducting expenses.  These settlement positions involve the 2002-2004 tax years, and if finally agreed upon, would result in a decrease in unrecognized tax benefits in the range of $20 million to $22 million, of which the tax impact on earnings is not expected to be material.  These ranges are $7 million to $8 million for CL&P, $9 million to $10 million for PSNH and $2 million to $3 million for WMECO.


J.

Other Taxes


Certain excise taxes levied by state or local governments are collected by NU from its customers.  These excise taxes are accounted for on a gross basis with collections in revenues and payments in expenses.  For the three and six months ended June 30, 2008, gross receipts taxes, franchise taxes and other excise taxes of $27.4 million and $58.4 million, respectively, were included in operating revenues and taxes other than income taxes on the accompanying condensed consolidated statements of income.  For the three and six months ended June 30, 2007, these amounts totaled $26.3 million and $58 million, respectively.  Certain sales taxes are also collected by the regulated companies from their customers as agents for state and local governments and are recorded on a net basis with no impact on the accompanying condensed consolidated statements of income.  


2.

DERIVATIVE INSTRUMENTS (NU, Select Energy, CL&P, PSNH, Yankee Gas)


Contracts that are derivatives and do not meet the requirements to be treated as a cash flow hedge or normal purchase or normal sale are recorded at fair value with changes in fair value included in earnings.  For those contracts that meet the definition of a derivative and meet the cash flow hedge requirements, including those related to initial and ongoing documentation, the contract is recorded at fair value and the changes in the fair value of the effective portion of those contracts are recognized in accumulated other comprehensive income.  Cash flow hedges include forward interest rate swap agreements on proposed debt issuances.  When a cash flow hedge is settled, the settlement amount is recorded in accumulated other comprehensive income and is amortized into earnings over the term of the debt.  Cash flow hedges impact net income when the hedged items affect earnings, when hedge ineffectiveness is measured and recorded, or when the forecasted transaction being hedged is improbable of occurring.  Derivative contracts designated as fair value hedges and the items they are hedging are both recorded at fair value with changes in fair value of both items recognized in earnings.  Derivative contracts that meet the requirements of a normal purchase or sale, and are so designated, are recognized in revenues or expenses, as applicable, when the quantity of the contract is delivered.  


The fair value of the company's derivative contracts may not represent amounts that will be realized.  For further information on the fair value of derivative contracts, see Note 1C, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 3, "Fair Value Measurements," to the condensed consolidated financial statements.  On the accompanying condensed consolidated balance sheets at June 30, 2008 and December 31, 2007, these amounts are recorded as current or long-term derivative assets or liabilities and are summarized as follows:



12





 

 

At June 30, 2008

 

 

Assets

 

Liabilities

 

 

 

 

Current

 

Long-Term

 

Current

 

Long-Term

 

Net Totals

(Millions of Dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU Enterprises - Wholesale

 

$

22.1 

 

$

22.5 

 

$

(33.7)

 

$

(85.5)

 

$

(74.6)

Regulated Companies - Gas:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Supply

 

 

0.1 

 

 

1.6 

 

 

(0.1)

 

 

 

 

1.6 

  Interest Rate Hedging

 

 

0.8 

 

 

 

 

 

 

 

 

0.8 

Regulated Companies - Electric:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Supply/Stranded Costs

 

 

154.8 

 

 

420.7 

 

 

(2.1)

 

 

(725.6)

 

 

(152.2)

NU Parent:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Interest Rate Hedging

 

 

 

 

1.8 

 

 

 

 

 

 

1.8 

Totals

 

$

177.8 

 

$

446.6 

 

$

(35.9)

 

$

(811.1)

 

$

(222.6)


 

 

At December 31, 2007

 

 

Assets

 

Liabilities

 

 

 

 

Current

 

Long-Term

 

Current

 

Long-Term

 

Net Totals

(Millions of Dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NU Enterprises - Wholesale

 

$

36.2 

 

$

7.2 

 

$

(64.9)

 

$

(72.5)

 

$

(94.0)

Regulated Companies - Gas:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Supply

 

 

0.2 

 

 

 

 

 

 

 

 

0.2 

  Interest Rate Hedging

 

 

0.9 

 

 

 

 

 

 

 

 

0.9 

Regulated Companies - Electric:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Supply/Stranded Costs

 

 

59.8 

 

 

290.8 

 

 

(6.7)

 

 

(136.0)

 

 

207.9 

  Interest Rate Hedging

 

 

3.3 

 

 

 

 

 

 

 

 

3.3 

NU Parent:  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Interest Rate Hedging

 

 

5.1 

 

 

 

 

 

 

 

 

5.1 

Totals

 

$

105.5 

 

$

298.0 

 

$

(71.6)

 

$

(208.5)

 

$

123.4 


For the regulated companies, except for existing interest rate swap agreements, offsetting regulatory assets or liabilities are recorded for the changes in fair value of their contracts, as these contracts were part of the stranded costs or are current regulated operating costs, and management believes that these costs will continue to be recovered or refunded in cost-of-service, regulated rates.


The business activities of NU Enterprises that result in the recognition of derivative assets also result in exposures to credit risk of energy marketing and trading counterparties.  At June 30, 2008, Select Energy had $44.6 million of derivative assets from wholesale activities that are exposed to counterparty credit risk, a significant portion of which is contracted with several creditworthy and rated public entities.


NU Enterprises - Wholesale:  Certain electric derivative contracts are part of NU Enterprises' remaining wholesale marketing business.  These contracts include short-term and long-term electric supply contracts and a contract to sell electricity to the New York Municipal Power Agency (NYMPA) (an agency that is comprised of municipalities) that expires in 2013.  The fair value of the contracts was determined using prices from external sources through 2011 for on-peak and off-peak periods and through 2012 for on-peak periods, except for one contract, under which a portion of the fair value is also determined from a model based on natural gas prices and a heat-rate conversion factor to electricity for off-peak periods in 2012 and for all periods in 2013.  The 2007 balances also included a full requirements contract and the related short-term supply contracts to sell electricity to a utility.  These contracts expired on May 31, 2008.  

 

Regulated Companies - Gas - Supply:  Yankee Gas's supply derivatives consist of peaking supply arrangements to serve winter load obligations and firm retail sales contracts with options to curtail delivery.  These contracts are subject to fair value accounting as these contracts are derivatives that cannot be designated as normal purchases and sales because of the optionality in the contract terms.  An offsetting regulatory liability/asset was recorded for these amounts as management believes that these costs will be refunded or recovered in rates.


Regulated Companies - Gas - Interest Rate Hedging:   Yankee Gas has a forward interest rate swap agreement to hedge the interest cash outflows associated with its planned $100 million debt issuance in September 2008.  The interest rate swap is based on a 10-year LIBOR swap rate and matches the index used for the debt issuance.  As a cash flow hedge, the fair value of the hedge is recorded as a derivative liability and derivative asset on the accompanying condensed consolidated balance sheets as of June 30, 2008 and December 31, 2007, respectively, with an offsetting amount, net of tax, included in accumulated other comprehensive income.  




13




Regulated Companies - Electric - Supply/Stranded Costs :  CL&P has contracts with two IPPs to purchase power that contain pricing provisions that are not clearly and closely related to the price of power and therefore do not qualify for the normal purchases and sales exception.  The fair values of these derivatives at June 30, 2008 included a derivative asset with a fair value of $381 million and a derivative liability with a fair value of $38.2 million.  An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of stranded costs, and management believes that these costs will continue to be recovered or refunded in cost-of-service, regulated rates.  At December 31, 2007, the fair values of these derivatives included a derivative asset with a fair value of $311.2 million and a derivative liability with a fair value of $31.8 million.


CL&P has entered into FTR contracts and bilateral basis swaps to limit the congestion costs associated with its standard offer contracts.  An offsetting regulatory asset or liability has been recorded as management believes that these costs will be recovered or refunded in rates.  At June 30, 2008, the fair value of these contracts was recorded as a derivative asset of $3.2 million on the accompanying condensed consolidated balance sheets.  At December 31, 2007, the fair value of these contracts was recorded as a derivative asset of $1.4 million and a derivative liability of $1.3 million on the accompanying condensed consolidated balance sheets.  


Pursuant to Public Act 05-01, "An Act Concerning Energy Independence," in August 2007, the Connecticut Department of Public Utility Control (DPUC) approved two CL&P contracts associated with the capacity of two generating projects to be built or modified.  The DPUC also approved two capacity-related contracts entered into by The United Illuminating Company (UI), one with a generating project to be built and one with a new demand response project.  The total capacity of these four projects is expected to be approximately 787 megawatts (MW).  The contracts, referred to as CfDs, obligate the utilities' customers to pay the difference between a set capacity price and the forward capacity market price that the projects receive in the New England Independent System Operator (ISO-NE) capacity markets for periods of up to 15 years beginning in 2009.  As directed by the DPUC, CL&P has an agreement with UI under which it will share the costs and benefits of these four CfDs, with 80 percent to CL&P and 20 percent to UI.  The ultimate cost to CL&P under the contracts will depend on the capacity prices that the projects receive in the ISO-NE capacity markets.  At June 30, 2008, the fair value of the CL&P CfDs was recorded as a derivative liability of $689.5 million.  The fair values of UI's share of the CL&P's contracts and CL&P's share of UI's contracts were recorded as a derivative asset of $98.6 million.  An offsetting regulatory asset of $590.9 million was recorded, as management believes these amounts will be recovered from or refunded to customers in cost-of-service, regulated rates.  The value of CL&P's CfDs at June 30, 2008 included approximately $100 million of initial gains and losses, previously deferred due to the use of significant unobservable inputs in the valuation, that were recorded upon adoption of SFAS No. 157 on January 1, 2008.  At December 31, 2007, changes in CfD fair values since inception were recorded as a derivative liability of $107.1 million, and UI's share and one CL&P CfD were recorded as derivative assets of $20.8 million.  Offsetting regulatory assets of $86.7 million and regulatory liabilities of $0.4 million were also recorded at December 31, 2007.  A 2007 NRG Energy, Inc. (NRG) appeal of the DPUC's decision selecting the CfDs was taken into consideration in valuing the CfDs as of December 31, 2007, reducing the net negative derivative values by approximately $215 million.  In February 2008, the appeal was denied, which increased derivative liabilities in 2008.


PSNH has electricity procurement contracts that are derivatives.  The fair values of these contracts are calculated based on market prices and were recorded as derivative assets totaling $51.8 million at June 30, 2008.  At December 31, 2007, the fair value was recorded as a derivative asset of $1.5 million and a derivative liability of $2.5 million.  An offsetting regulatory liability/asset was recorded as management believes that these costs will be refunded or recovered in rates as the energy is delivered.


PSNH has a contract to assign its transmission rights in a direct current transmission line in exchange for two energy call options which expire in 2010.  These energy call options are derivatives that do not qualify for the normal purchases and sales exception and are accounted for at fair value based on market prices.  At June 30, 2008 and December 31, 2007, the options were recorded as a derivative asset of $40.9 million and $15.7 million, respectively.  An offsetting regulatory liability was recorded, as the benefit of this arrangement will be refunded to customers in rates.    


Regulated Companies - Electric - Interest Rate Hedging:  At December 31, 2007, CL&P had two forward interest rate swap agreements to hedge the interest cash outflows associated with its debt issuance of $300 million in May 2008.  PSNH had a forward interest rate swap agreement to hedge the interest cash outflows associated with its debt issuance of $110 million in May 2008.  Prior to termination in May 2008, the interest rate swaps were based on a 10-year LIBOR swap rate and matched the index used for the debt issuances.  As cash flow hedges, the fair values of these hedges were recorded as derivative assets at December 31, 2007 on the accompanying condensed consolidated balance sheet with an offsetting amount, net of tax, included in accumulated other comprehensive income.


NU Parent - Interest Rate Hedging:   In March 2003, to manage the interest rate characteristics of the company's long-term debt, NU parent entered into a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed rate senior notes that mature on April 1, 2012.  Under fair value hedge accounting, the changes in fair value of the swap and the interest component of the hedged long-term debt instrument are recorded in interest expense, which generally offset each other in the condensed consolidated statements of income.  The cumulative change in the fair value of the swap and the long-term debt was recorded as a derivative asset and an increase to long-term debt of $1.8 million and $4.2 million at June 30, 2008 and December 31, 2007, respectively.  



14





NU parent had a forward interest rate swap agreement to hedge the interest cash outflows associated with its planned debt issuance in June 2008.  Prior to termination in June 2008, the interest rate swap was based on a 5-year LIBOR swap rate and a notional amount of $200 million, and matched the index used for the debt issuance.  As a cash flow hedge at December 31, 2007, the fair value of the hedge was recorded as a $0.9 million derivative asset on the accompanying condensed consolidated balance sheet with an offsetting amount, net of tax, included in accumulated other comprehensive income.


3.

FAIR VALUE MEASUREMENTS (All Companies)


Items Measured at Fair Value on a Recurring Basis:   The company's assets and liabilities recorded at fair value on a recurring basis have been categorized based upon the fair value hierarchy in accordance with SFAS No. 157.  See Note 1C, "Summary of Significant Accounting Policies - Fair Value Measurements," for further information regarding the hierarchy and fair value measurements.


The following table presents the amounts of assets and liabilities carried at fair value at June 30, 2008 by the level in which they are classified within the SFAS No. 157 valuation hierarchy:



(Millions of Dollars)

 

Total NU

 

CL&P

 

PSNH

 

WMECO

 

NU
Enterprises

 

Yankee Gas

 

NU Parent

Derivative Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Level 1

 

$

 

$

 

$

 

$

 

$

 

$

 

$

  Level 2

 

 

54.4 

 

 

 

 

51.8 

 

 

 

 

 

 

0.8 

 

 

1.8 

  Level 3

 

 

570.0 

 

 

482.8 

 

 

40.9 

 

 

 

 

44.6 

 

 

1.7 

 

 

Total

 

$

624.4 

 

$

482.8 

 

$

92.7 

 

$

 

$

44.6 

 

$

2.5 

 

$

1.8 

Derivative Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Level 1

 

$

 

$

 

$

 

$

 

$

 

$

 

$

  Level 2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Level 3

 

 

(847.0)

 

 

(727.7)

 

 

 

 

 

 

(119.2)

 

 

(0.1)

 

 

Total

 

$

(847.0)

 

$

(727.7)

 

$

 

$

 

$

(119.2)

 

$

(0.1)

 

$

Marketable Securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Level 1

 

$

43.5 

 

$

 

$

 

$

6.6 

 

$

 

$

 

$

36.9 

  Level 2

 

 

77.6 

 

 

 

 

 

 

50.1 

 

 

 

 

 

 

27.5 

  Level 3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

121.1 

 

$

 

$

 

$

56.7 

 

$

 

$

 

$

64.4 


The following tables present changes for the three and six months ended June 30, 2008 in the Level 3 category of assets and liabilities measured at fair value on a recurring basis.  This category includes derivative assets and liabilities, which are presented net.  The derivative amounts at January 1, 2008 reflect the fair values after initial adoption of SFAS No. 157.  The company classifies assets and liabilities in Level 3 of the fair value hierarchy when there is reliance on at least one significant unobservable input to the valuation model.  In addition to these unobservable inputs, the valuation models for Level 3 assets and liabilities typically also rely on a number of inputs that are observable either directly or indirectly.  Thus, the gains and losses presented below include changes in fair value that are attributable to both observable and unobservable inputs.  There were no transfers into or out of Level 3 assets and liabilities for the three and six months ended June 30, 2008.


 

 

For the Three Months Ended June 30, 2008


(Millions of Dollars)

 

Total NU

 

CL&P

 

PSNH

 

NU
Enterprises

 

Yankee
Gas

Derivatives, Net :

 

 

 

 

 

 

 

 

 

 

Fair value at March 31, 2008

 

$

(488.5)

 

$

(430.3)

 

$

22.8 

 

$

(81.1)

 

$

0.1 

Net realized/unrealized
  gains included in:  

 

 


 

 

 


 

 

 


 

 

 

 

 

 

 

    Earnings (1)

 

 

1.2 

 

 

 

 

 

 

1.2 

 

 

    Regulatory assets/liabilities

 

 

228.7 

 

 

209.1 

 

 

18.1 

 

 

 

 

1.5 

Purchases, issuances and
  settlements

 

 


(18.4)

 

 


(23.7)

 

 


 

 


5.3 

 

 


Fair value at June 30, 2008

 

$

(277.0)

 

$

(244.9)

 

$

40.9 

 

$

(74.6)

 

$

1.6 

Quarterly change in unrealized losses
  included in earnings relating to items
 held at June 30, 2008

 



$

(2.3)

 



$

 



$

 



$

                (2.3)

 



$




15






 

 

For the Six Months Ended June 30, 2008


(Millions of Dollars)

 

Total NU

 

CL&P

 

PSNH

 

NU
Enterprises

 

Yankee
Gas

Derivatives, Net :

 

 

 

 

 

 

 

 

 

 

Fair value at January 1, 2008 (2)

 

$

(511.1)

 

$

(426.9)

 

$

15.7 

 

$

(100.1)

 

$

0.2 

Net realized/unrealized
  gains included in:  

 

 


 

 

 


 

 

 


 

 

 

 

 

 

 

    Earnings (1)

 

 

4.8 

 

 

 

 

 

 

4.8 

 

 

    Regulatory assets/liabilities

 

 

245.5 

 

 

218.9 

 

 

25.2 

 

 

 

 

1.4 

Purchases, issuances and
  settlements

 

 


(16.2)

 

 


(36.9)

 

 


 

 


20.7 

 

 


Fair value at June 30, 2008

 

$

(277.0)

 

$

(244.9)

 

$

40.9 

 

$

(74.6)

 

$

1.6 

Period change in unrealized losses
 included in earnings relating to
  items held at June 30, 2008

 



$

(1.5)

 



$

 



$

 



$

(1.5)

 



$


(1)

Realized and unrealized gains and losses on derivatives included in earnings relate to the remaining Select Energy wholesale marketing contracts and are reported in fuel, purchased and net interchange power on the accompanying condensed consolidated statements of income.  


(2)

Amounts as of January 1, 2008 reflect fair values after initial adoption of SFAS No. 157.  As a result of implementing SFAS No. 157, the company recorded an increase to derivative liabilities and a pre-tax charge to earnings of $6.1 million as of January 1, 2008 related to NU Enterprises' remaining derivative contracts.  The company also recorded changes in fair value of CL&P's CfD and IPP contracts, resulting in increases to CL&P's derivative liabilities of approximately $590 million, with an offset to regulatory assets and a decrease to CL&P's derivative assets of approximately $30 million with an offset to regulatory liabilities.  


4.

PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (All Companies)


NU's subsidiaries participate in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees and also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (post-retirement benefits other than pension (PBOP) Plan).  In addition, NU maintains a Supplemental Executive Retirement Plan (SERP) which provides benefits to eligible participants, who are officers of NU, that would have been provided to them under the Pension Plan if certain Internal Revenue Code and other limitations were not imposed.  


The components of net periodic expense/(income) for the Pension Plan, PBOP Plan and SERP for the three and six months ended June 30, 2008 and 2007 are as follows:


NU

 

For the Three Months Ended June 30,

 

 

Pension Benefits

 

Postretirement Benefits

 

SERP Benefits

(Millions of Dollars)

 

2008

 

2007

 

2008

 

2007

 

2008

 

2007

Service cost

 

$

11.1 

 

$

12.5 

 

$

1.8 

 

$

2.1 

 

$

0.2 

 

$

0.2 

Interest cost

 

 

35.9 

 

 

35.5 

 

 

7.0 

 

 

6.6 

 

 

0.5 

 

 

0.5 

Expected return on plan assets

 

 

(50.0)

 

 

(51.2)

 

 

(5.3)

 

 

(4.5)

 

 

 

 

Amortization of unrecognized net
  transition obligation

 

 


 

 


0.1 

 

 


2.9 

 

 


2.9 

 

 


 

 


0.2 

Amortization of prior service cost

 

 

2.5 

 

 

2.3 

 

 

(0.1)

 

 

(0.1)

 

 

 

 

Amortization of actuarial loss

 

 

1.1 

 

 

5.0 

 

 

2.7 

 

 

2.9 

 

 

0.1 

 

 

Net periodic expense

 

$

0.6 

 

$

4.2 

 

$

9.0 

 

$

9.9 

 

$

0.8 

 

$

0.9 




16





NU

 

For the Six Months Ended June 30,

 

 

Pension Benefits

 

Postretirement Benefits

 

SERP Benefits

(Millions of Dollars)

 

2008

 

2007

 

2008

 

2007

 

2008

 

2007

Service cost

 

$

21.8 

 

$

24.3 

 

$

3.6 

 

$

4.2 

 

$

0.3 

 

$

0.4 

Interest cost

 

 

72.1 

 

 

69.1 

 

 

14.1 

 

 

13.3 

 

 

1.0 

 

 

1.0 

Expected return on plan assets

 

 

(100.1)

 

 

(98.4)

 

 

(10.5)

 

 

(9.1)

 

 

 

 

Amortization of unrecognized net
  transition obligation

 

 


0.1 

 

 


0.1 

 

 


5.8 

 

 


5.8 

 

 


 

 


Amortization of prior service cost

 

 

4.9 

 

 

3.9 

 

 

(0.2)

 

 

(0.1)

 

 

0.1 

 

 

0.3 

Amortization of actuarial loss

 

 

2.5 

 

 

11.8 

 

 

5.3 

 

 

5.8 

 

 

0.1 

 

 

0.1 

Net periodic expense

 

$

1.3 

 

$

10.8 

 

$

18.1 

 

$

19.9 

 

$

1.5 

 

$

1.8 


A portion of these pension amounts is capitalized related to current employees that are working on capital projects.  Amounts capitalized were approximately $1.3 million and $2.7 million for the three and six months ended June 30, 2008, respectively, and $(0.2) million and $0.4 million for the three and six months ended June 30, 2007, respectively.  The amounts for the three and six months ended June 30, 2008 offset capital costs, as pension income was recorded for certain of NU’s subsidiaries.


CL&P

 

For the Three Months Ended June 30,

 

 

Pension Benefits

 

Postretirement Benefits

 

SERP Benefits

(Millions of Dollars)

 

2008

 

2007

 

2008

 

2007

 

2008

 

2007

Service cost

 

$

3.9 

 

$

4.5 

 

$

0.6 

 

$

0.7 

 

$

 

$

Interest cost

 

 

12.8 

 

 

12.4 

 

 

2.8 

 

 

2.6 

 

 

0.1 

 

 

0.1 

Expected return on plan assets

 

 

(23.4)

 

 

(23.6)

 

 

(2.1)

 

 

(1.8)

 

 

 

 

Amortization of unrecognized net
  transition obligation

 

 


 

 


 

 


1.5 

 

 


1.6 

 

 


 

 

Amortization of prior service cost

 

 

1.1 

 

 

1.0 

 

 

 

 

 

 

 

 

Amortization of actuarial loss

 

 

0.3 

 

 

1.4 

 

 

1.1 

 

 

1.1 

 

 

 

 

Net periodic (income)/expense

 

$

(5.3)

 

$

(4.3)

 

$

3.9 

 

$

4.2 

 

$

0.1 

 

$

0.1 


CL&P

 

For the Six Months Ended June 30,

 

 

Pension Benefits

 

Postretirement Benefits

 

SERP Benefits

(Millions of Dollars)

 

2008

 

2007

 

2008

 

2007

 

2008

 

2007

Service cost

 

$

7.6 

 

$

8.4 

 

$

1.1 

 

$

1.4 

 

$

 

$

Interest cost

 

 

25.7 

 

 

24.7 

 

 

5.7 

 

 

5.3 

 

 

0.1 

 

 

0.1 

Expected return on plan assets

 

 

(46.7)

 

 

(45.7)

 

 

(4.2)

 

 

(3.6)

 

 

 

 

Amortization of unrecognized net
  transition obligation

 

 


 

 


 

 


3.1 

 

 


3.1 

 

 


 

 


Amortization of prior service cost

 

 

2.1 

 

 

1.7 

 

 

 

 

 

 

 

 

Amortization of actuarial loss

 

 

0.6 

 

 

3.9 

 

 

2.2 

 

 

2.2 

 

 

0.1 

 

 

0.1 

Net periodic (income)/expense

 

$

(10.7)

 

$

(7.0)

 

$

7.9 

 

$

8.4 

 

$

0.2 

 

$

0.2 


Not included in the pension income amounts above are related intercompany allocations totaling $1.9 million and $4 million for the three and six months ended June 30, 2008, respectively, and $2.9 million and $6 million for the three and six months ended June 30, 2007, respectively.  Excluded from postretirement benefits are related intercompany allocations of $1.7 million and $3.4 million for the three and six months ended June 30, 2008, respectively, and $1.8 million and $3.6 million for the three and six months ended June 30, 2007, respectively.  Excluded from SERP expenses are related intercompany allocations of $0.4 million and $0.8 million for the three and six months ended June 30, 2008, respectively, and $0.5 million and $1.0 million for the three and six months ended June 30, 2007, respectively.  


For CL&P, a portion of the pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects.  Amounts capitalized were $2.2 million and $4.4 million for the three and six months ended June 30, 2008, respectively, and $1.3 million and $1.9 million for the three and six months ended June 30, 2007, respectively.  These amounts offset capital costs, as pension income was recorded for those periods.



17





PSNH

 

For the Three Months Ended June 30,

 

 

Pension Benefits

 

Postretirement Benefits

 

SERP Benefits

(Millions of Dollars)

 

2008

 

2007

 

2008

 

2007

 

2008

 

2007

Service cost

 

$

2.3 

 

$

2.4 

 

$

0.4 

 

$

0.5 

 

$

 

$

Interest cost

 

 

5.8 

 

 

5.7 

 

 

1.3 

 

 

1.2 

 

 

 

 

Expected return on plan assets

 

 

(4.5)

 

 

(4.7)

 

 

(1.0)

 

 

(0.8)

 

 

 

 

Amortization of unrecognized net
  transition obligation

 

 


 

 


0.1 

 

 


0.6 

 

 


0.6 

 

 


 

 



Amortization of prior service cost

 

 

0.5 

 

 

0.5 

 

 

 

 

 

 

 

 

Amortization of actuarial loss

 

 

0.4 

 

 

1.0 

 

 

0.5 

 

 

0.5 

 

 

0.1 

 

 

0.1 

Net periodic expense

 

$

4.5 

 

$

5.0 

 

$

1.8 

 

$

2.0 

 

$

0.1 

 

$

0.1 


PSNH

 

For the Six Months Ended June 30,

 

 

Pension Benefits

 

Postretirement Benefits

 

SERP Benefits

(Millions of Dollars)

 

2008

 

2007

 

2008

 

2007

 

2008

 

2007

Service cost

 

$

4.5 

 

$

5.0 

 

$

0.8 

 

$

0.9 

 

$

 

$

Interest cost

 

 

11.6 

 

 

11.0 

 

 

2.6 

 

 

2.5 

 

 

 

 

0.1 

Expected return on plan assets

 

 

(9.0)

 

 

(9.0)

 

 

(2.0)

 

 

(1.7)

 

 

 

 

Amortization of unrecognized net
  transition obligation

 

 


0.2 

 

 


0.1 

 

 


1.2 

 

 


1.2 

 

 


 

 

Amortization of prior service cost

 

 

0.9 

 

 

0.8 

 

 

 

 

 

 

 

 

Amortization of actuarial loss

 

 

0.8 

 

 

2.2 

 

 

0.9 

 

 

1.1 

 

 

0.1 

 

 

0.1 

Net periodic expense

 

$

9.0 

 

$

10.1 

 

$

3.5 

 

$

4.0 

 

$

0.1 

 

$

0.2 


Not included in the pension expense amounts above are related intercompany allocations totaling $0.4 million and $0.8 million for the three and six months ended June 30, 2008, respectively, and $0.5 million and $1 million for the three and six months ended June 30, 2007, respectively.  Excluded from postretirement benefits are related intercompany allocations of $0.4 million and $0.7 million for the three and six months ended June 30, 2008, respectively, and $0.3 million and $0.6 million for the three and six months ended June 30, 2007, respectively.  Excluded from SERP expenses are related intercompany allocations of $0.1 million and $0.2 million for the three and six months ended June 30, 2008 and 2007, respectively.  


For PSNH, a portion of these pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects.  Amounts capitalized were $1.2 million and $2.3 million for the three and six months ended June 30, 2008, respectively, and $1.2 million and $2.5 million for the three and six months ended June 30, 2007, respectively.


WMECO

 

For the Three Months Ended June 30,

 

For the Six Months Ended June 30,

 

 

Pension Benefits

 

Postretirement Benefits

 

Pension Benefits

 

Postretirement Benefits

 

 

2008

 

2007

 

2008

 

2007

 

2008

 

2007

 

2008

 

2007

(Millions of Dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

0.8 

 

$

1.0 

 

$

0.1 

 

$

0.2 

 

$

1.6 

 

$

1.7 

 

$

0.2 

 

$

0.3 

Interest cost

 

 

2.6 

 

 

2.5 

 

 

0.6 

 

 

0.6 

 

 

5.2 

 

 

5.0 

 

 

1.2 

 

 

1.1 

Expected return on plan assets

 

 

(5.1)

 

 

(5.2)

 

 

(0.5)

 

 

(0.5)

 

 

(10.4)

 

 

(10.1)

 

 

(1.0)

 

 

(0.9)

Amortization of unrecognized net
  transition obligation

 

 


 

 


 

 


0.4 

 

 


0.3 

 

 


 

 


 

 


0.7 

 

 


0.7 

Amortization of prior service cost

 

 

0.2 

 

 

0.2 

 

 

 

 

 

 

0.5 

 

 

0.4 

 

 

 

 

Amortization of actuarial loss

 

 

 

 

0.2 

 

 

0.1 

 

 

0.2 

 

 

0.1 

 

 

0.7 

 

 

0.3 

 

 

0.4 

Net periodic (income)/expense

 

$

(1.5)

 

$

(1.3)

 

$

0.7 

 

$

0.8 

 

$

(3.0)

 

$

(2.3)

 

$

1.4 

 

$

1.6 


A de minimis amount of SERP expense was recorded for WMECO for each of the three and six months ended June 30, 2008 and 2007.


Not included in the pension income amounts above are related intercompany allocations totaling $0.4 million and $0.7 million for the three and six months ended June 30, 2008, respectively, and $0.5 million and $1 million for the three and six months ended June 30, 2007, respectively.  Excluded from postretirement benefits are related intercompany allocations of $0.3 million and $0.5 million for the three and six months ended June 30, 2008, respectively, and $0.3 million and $0.6 million for the three and six months ended June 30, 2007, respectively.


For WMECO, a portion of these pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects.  Amounts capitalized were $0.5 million and $1.1 million for the three and six months ended June 30, 2008, respectively, and $0.5 million and $0.8 million for the three and six months ended June 30, 2007, respectively.  These amounts offset capital costs, as pension income was recorded for those periods.  




18




5.

COMMITMENTS AND CONTINGENCIES


A.

Regulatory Developments and Rate Matters (CL&P, PSNH, WMECO, Yankee Gas)


Connecticut:


CTA and SBC Reconciliation:  The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with its rate reduction bonds, amortization of regulatory assets, and IPP over-market costs, while the System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced worker protection costs.


On March 31, 2008, CL&P filed with the DPUC its 2007 CTA and SBC reconciliation, which compared CTA and SBC revenues to revenue requirements.  For the 12 months ended December 31, 2007, total CTA revenues exceeded CTA revenue requirements by $26.1 million.  This amount was recorded as a decrease to the CTA regulatory asset on the accompanying condensed consolidated balance sheets.  For the 12 months ended December 31, 2007, the SBC cost of service exceeded SBC revenues by $39.4 million.  This amount was recorded as a regulatory asset on the accompanying condensed consolidated balance sheets.  Management expects a decision in this docket from the DPUC by the end of 2008 and does not expect the outcome to have a material adverse impact on CL&P's net income, financial position or cash flows.


Procurement Fee Rate Proceedings:   CL&P was allowed to collect a fixed procurement fee of 0.50 mills per kilowatt-hour (KWH) from customers that purchased transitional standard offer (TSO) service from 2004 through the end of 2006.  One mill is equal to one tenth of a cent.  That fee could increase to 0.75 mills per KWH if CL&P outperforms certain regional benchmarks.  CL&P submitted to the DPUC its proposed methodology to calculate the variable incentive portion of the procurement fee and requested approval of $5.8 million in incentive fees.  On December 8, 2005, a draft decision was issued in this docket, which accepted the methodology as proposed by CL&P and authorized payment of the pre-tax $5.8 million incentive fee.  Subsequent to this draft decision the record was re-opened for numerous inputs.  Additional hearings were held on December 10, 2007 and January 30, 2008 and the record was then closed.  A date for the new draft decision in this docket has not yet been determined by the DPUC.  Management continues to believe that final regulatory approval of the $5.8 million pre-tax amount, which was reflected in 2005 earnings, is probable.  


Purchased Gas Adjustment: In 2005 and 2006, the DPUC issued decisions regarding Yankee Gas’s Purchased Gas Adjustment (PGA) clause charges and required an audit of previously recovered PGA revenues of approximately $11 million associated with unbilled sales and revenue adjustments for the period of September 1, 2003 through August 31, 2005.  On June 11, 2008, the DPUC issued a final order requiring Yankee Gas to refund approximately $5.8 million in previous recoveries to its customers.  The $5.8 million pre-tax charge (approximately $3.5 million net of tax) was recorded in the second quarter 2008 earnings of Yankee Gas.  


New Hampshire:


ES and SCRC Reconciliation and Rates:   On an annual basis, PSNH files with the New Hampshire Public Utilities Commission (NHPUC) a default energy service charge/stranded cost recovery charge (ES/SCRC) reconciliation filing for the preceding year.  The NHPUC reviews the filing, which includes a prudence review of PSNH's generation business segment operations.  On May 1, 2008, PSNH filed its 2007 ES/SCRC reconciliation with the NHPUC.  On June 27, 2008, the NHPUC issued a procedural schedule, with hearings scheduled in November 2008.  Management does not expect the outcome of the NHPUC review to have a material adverse impact on PSNH's net income, financial position or cash flows.


Massachusetts:


Transition Cost Reconciliations:   WMECO filed its 2005 transition cost reconciliation with the Massachusetts Department of Public Utilities (DPU) on March 31, 2006 and filed its 2006 transition cost reconciliation with the DPU on March 31, 2007.  The DPU opened a proceeding for these filings, and evidentiary hearings were held on August 29, 2007.  The briefing process was completed during October 2007.  On June 20, 2008, the DPU issued its final decision on these filings, which resulted in a pre-tax charge of $1.6 million to WMECO’s condensed consolidated statements of income for the three and six months ended June 30, 2008.  The DPU ordered WMECO to use a return on equity of 11 percent, and not the allowed return on equity of 9.85 percent in 2005 and 2006, for purposes of calculating carrying cost credits for customers on the stranded cost deferrals.  In addition, the DPU ordered WMECO not to combine certain overrecoveries and underrecoveries but instead, to keep them separate and to calculate carrying costs on certain balances using a return on equity of 11 percent and to use customer deposit rates on other balances.  The impacts of this order on WMECO's calculations of the 2007 and year to date 2008 transition cost reconciliations were recorded in the second quarter of 2008.  


On July 18, 2008, WMECO filed its 2007 transition cost reconciliation with the DPU.  The schedule for reviewing this filing will be set by the DPU at a later date.  Management does not expect the outcome of the DPU's review of this filing to have a material adverse effect on WMECO's net income, financial position or cash flows.   



19




 

B.

Long-Term Contractual Arrangements (CL&P, Select Energy)


Estimated Future Annual CL&P Costs :  The estimated future annual costs of CL&P’s renewable energy contract arrangements, updated as of June 30, 2008, are as follows:  


(Millions of Dollars)

 

2008

 

2009

 

2010

 

2011

 

2012

 

Thereafter

 

Total

Renewable energy
  contracts

 


$


1.2 

 


$


18.0 

 


$


30.5 

 


$


71.9 

 


$


101.1 

 


$


1,558.9 

 


$


1,781.6 


CL&P has entered into various agreements to purchase energy, capacity and renewable energy credits from renewable energy facilities.  Amounts payable under these contracts are subject to a sharing agreement with UI, whereby UI will share 20 percent of the costs and benefits of these contracts.  In addition, UI has entered into a contract that is subject to this cost sharing agreement under which CL&P will share in approximately 80 percent of the costs and benefits of the contract.  The information in the table above includes 100 percent of the payments projected under the contracts entered into by CL&P and 80 percent of the payments projected under the contract entered into by UI.  CL&P’s portion of the costs and benefits of these contracts will be paid by or refunded to CL&P’s customers.


Estimated Future Annual NU Enterprises Costs :  The estimated future annual costs of NU Enterprises' significant contractual arrangements, updated as of June 30, 2008, are as follows:  


(Millions of Dollars)

 

2008

 

2009

 

2010

 

2011

 

2012

 

Thereafter

 

Total

Select Energy purchase
 agreements

 


$


30.0 

 


$


36.0 

 


$


38.4 

 


$


42.9 

 


$


38.8 

 


$


44.7 

 


$


230.8 


Select Energy Purchase Agreements:   Select Energy maintains long-term agreements to purchase energy as part of its portfolio of resources to meet its actual or expected sales commitments.  Most purchase commitments are recorded at their mark-to-market value with the exception of one non-derivative contract which is accounted for on the accrual basis.  


Select Energy's purchase commitment amounts are reported on a net basis in fuel, purchased and net interchange power along with certain sales contracts and mark-to-market amounts.  Therefore, the amount included in fuel, purchased and net interchange power will be less than the amounts included in the table above.  Select Energy also maintains certain energy commitments for which mark-to-market values have been recorded on the condensed consolidated balance sheets as derivative assets and liabilities.  These contracts are included in the table above.  


C.

Environmental Matters (HWP)


HWP is a subsidiary of NU that owns a minimal amount of transmission property and has limited operating activities.  HWP continues to evaluate additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with a manufactured gas plant which it sold to Holyoke Gas and Electric (HG&E), a municipal electric utility, in 1902.  HWP is at least partially responsible for this site, and has already conducted substantial remediation activities.  HWP first established a reserve for this site in 1994.  A pre-tax charge of approximately $3 million was recorded in the second quarter of 2008 to reflect the estimated cost of further tar delineation and site characterization studies, as well as certain remediation costs that are considered to be probable and estimable as of June 30, 2008.  The cumulative expense recorded to this reserve through June 30, 2008 was approximately $15.9 million, of which $12.6 million had been spent, leaving approximately $3.3 million in the reserve as of June 30, 2008.  


The Massachusetts Department of Environmental Protection (MA DEP) issued a letter on April 3, 2008 to HWP and HG&E, which shares responsibility for the site, providing conditional authorization for additional investigatory and risk characterization activities and providing detailed comments on HWP’s 2007 reports and proposals for further investigations.  MA DEP also indicated that further removal of tar in certain areas was necessary prior to commencing many of the additional studies and evaluation.  This letter represents guidance from the MA DEP, rather than mandates.  HWP is developing plans for additional investigations to accord with MA DEP’s guidance letter, including estimated costs and schedules.  These matters are subject to ongoing discussions with MA DEP and HG&E and may change from time to time.


At this time, management believes that the $3.3 million remaining in the reserve is at the low end of a range of probable and estimable costs of approximately $3.3 million to $4 million and will be sufficient for HWP to conduct the additional tar delineation and site characterization studies, evaluate its approach to this matter and conduct certain soft tar remediation.  The additional studies are expected to occur through 2008 and 2009, and possibly into 2010.


There are many outcomes that could affect management's estimates and require an increase to the reserve, or range of costs, and a reserve increase would be reflected as a charge to pre-tax earnings.  However, management cannot reasonably estimate the range of



20




additional investigation and remediation costs because they will depend on, among other things, the level and extent of the remaining tar that may be required to be remediated, the extent of HWP’s responsibility and the related scope and timing, all of which are difficult to estimate because of a number of uncertainties at this time.  As of June 30, 2008, HWP had $3.3 million remaining in the reserve related to this matter, and further developments may require a material increase to this reserve.


HWP's share of the remediation costs related to this site is not recoverable from customers.  


D.

Guarantees and Indemnifications (All Companies)


NU provides credit assurances on behalf of subsidiaries in the form of guarantees and letters of credit (LOCs) in the normal course of business.  NU has also provided guarantees and various indemnifications on behalf of external parties as a result of the sales of Select Energy Services, Inc. (SESI), NU Enterprises' retail marketing business and its competitive generation business.  The following table summarizes NU's maximum exposure at June 30, 2008, in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," expiration dates, and fair value of amounts recorded.  





Company

 




Description

 


Maximum
Exposure
(in millions)

 

 



Expiration
Date(s)

 

Fair Value
of Amounts
Recorded
(in millions)

On behalf of external parties:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SESI

 

General indemnifications in connection with the sale of SESI including completeness and accuracy of information provided, compliance with laws, and various claims

 

Not Specified 

(1)

 

None

 

$  -

 

 

 

 

 

 

 

 

 

 

 

 

Specific indemnifications in connection with the sale of SESI for estimated costs to complete or modify specific projects

 

Not Specified 

(1)

 

Through project completion

 

$0.2

 

 

 

 

 

 

 

 

 

 

 

 

Indemnifications to lenders for payment of shortfalls in the event of early termination of government contracts

 

$1.7 

 

 

2017-2018

 

$0.1

 

 

 

 

 

 

 

 

 

 

 

 

Surety bonds covering certain projects

 

$10.5 

 

 

Through project
completion

 

$  -

 

 

 

 

 

 

 

 

 

 

Hess Corporation (Retail Marketing Business)

 

General indemnifications in connection with the sale including compliance with laws, completeness and accuracy of information provided, and various claims

 

Not Specified 

(1)

 

None

 

$  -

 

 

 

 

 

 

 

 

 

 

Energy Capital Partners (Competitive Generation Business)

 

General indemnifications in connection with the sale of NGC and the generating assets of Mt. Tom including compliance with tax and environmental laws, and various claims

 

Not Specified 

(1)

 

2008-2009

 

$  -

 

 

 

 

 

 

 

 

 

 

On behalf of subsidiaries:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulated Companies

 

Surety bonds, primarily for self-insurance

 

$13.6 

 

 

None

 

N/A

 

 

Letters of credit

 

$12.0 

 

 

2009

 

N/A

 

 

 

 

 

 

 

 

 

 

Rocky River Realty Company

 

Lease payments for real estate

 

$11.2 

 

 

2024

 

N/A

 

 

 

 

 

 

 

 

 

 

NUSCO

 

Lease payments for fleet of vehicles

 

$9.3 

 

 

None

 

N/A

 

 

Letters of credit

 

$6.0 

 

 

2009

 

N/A

 

 

 

 

 

 

 

 

 

 

E.S. Boulos Company (Boulos)

 

Surety bonds covering ongoing projects

 

$73.3 

 

 

Through project
completion

 

N/A

 

 

 

 

 

 

 

 

 

 

NGS

 

Performance guarantee and insurance bonds

 

$22.1 

(2)

 

2020 (2)

 

N/A

 

 

 

 

 

 

 

 

 

 

Select Energy

 

Performance guarantees and surety bonds for retail marketing contracts

 

$5.0 

(3)

 

None (4)

 

N/A

 

 

 

 

 

 

 

 

 

 

 

 

Performance guarantees for wholesale contracts

 

$26.7 

(3)

 

2013

 

N/A

 

 

 

 

 

 

 

 

 

 

 

 

Letters of credit

 

$2.0 

 

 

2009

 

N/A




21




(1)

There is no specified maximum exposure included in the related sale agreements.  


(2)

Included in the maximum exposure is $20.9 million related to a performance guarantee of Northeast Generation Services Company (NGS) obligations for which there is no specified maximum exposure in the agreement.  The maximum exposure is calculated based on limits on NGS's liability contained in the underlying service contract and assumes that NGS will perform under that contract through its expiration in 2020.  The remaining $1.2 million of maximum exposure relates to insurance bonds with no expiration date which are billed annually on their anniversary date.  


(3)

Maximum exposure is as of June 30, 2008; however, exposures vary with underlying commodity prices and for certain contracts are essentially unlimited.  


(4)

NU does not currently anticipate that these remaining guarantees on behalf of Select Energy will result in significant guarantees of the performance of Hess Corporation.


Many of the underlying contracts that NU guarantees, as well as certain surety bonds, contain provisions that would require NU to post collateral in the event that NU's credit ratings are downgraded below investment grade.  


In July 2006, under a guarantee of SESI obligations, NU purchased the right to receive contract payments relating to a SESI project that was financed and behind schedule.  The carrying value of these assets was $8.8 million at June 30, 2008 and is included in other deferred debits on the accompanying condensed consolidated balance sheets.  This carrying amount represents the net realizable value of the asset, which is subject to change through SESI's completion of the project.  NU may record additional losses associated with this transaction, the amount of which will depend on the amount of project cash available to offset NU's costs and other factors.  


6.

COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO, NU Enterprises, Yankee Gas)


Total comprehensive income, which includes all comprehensive income/(loss) items, net of tax and by category, for the three and six months ended June 30, 2008 and 2007 is as follows:


 

 

Three Months Ended June 30, 2008


(Millions of Dollars)

 


NU*

 


CL&P

 


PSNH

 


WMECO

 

NU
Enterprises

 

Yankee
Gas

 


Other

Net income/(loss)

 

$

57.8 

 

$

44.8 

 

$

13.7 

 

$

3.3 

 

$

2.2 

 

$

(1.0)

 

$

(5.2)

Comprehensive income/(loss) items:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Qualified cash flow hedging instruments

 

 

12.9 

 

 

4.9 

 

 

1.7 

 

 

 

 

 

 

2.5 

 

 

3.8 

  (Decreases)/increases in unrealized
   gains on securities

 

 

(0.1)

 

 

 

 

 

 

(0.2)

 

 

 

 

 

 

0.1 

  Pension, SERP, and other
    postretirement benefits

 

 


0.9 

 

 


 

 


 

 


 

 


0.7 

 

 


 

 


0.2 

Net change in comprehensive
   income/(loss) items

 

 


13.7 

 

 


4.9 

 

 


1.7 

 

 


(0.2)

 

 


0.7 

 

 


2.5 

 

 


4.1 

Total comprehensive income/(loss)

 

$

71.5 

 

$

49.7 

 

$

15.4 

 

$

3.1 

 

$

2.9 

 

$

1.5 

 

$

(1.1)


 

 

Three Months Ended June 30, 2007


(Millions of Dollars)

 


NU*

 


CL&P

 


PSNH

 


WMECO

 

NU
Enterprises

 

Yankee
Gas

 


Other

Net income

 

$

48.5 

 

$

24.4 

 

$

15.2 

 

$

4.6 

 

$

2.5 

 

$

0.3 

 

$

1.5 

Comprehensive income items:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Increase in unrealized gains on securities

 

 

1.2 

 

 

 

 

0.1 

 

 

 

 

 

 

 

 

1.1 

  Pension, SERP, and other
    postretirement benefits

 

 


5.8 

 

 


 

 


 

 


 

 


3.6 

 

 


 

 


2.2 

Net change in comprehensive
   income items

 

 


7.0 

 

 


 

 


0.1 

 

 


 

 


3.6 

 

 


 

 


3.3 

Total comprehensive income

 

$

55.5 

 

$

24.4 

 

$

15.3 

 

$

4.6 

 

$

6.1 

 

$

0.3 

 

$

4.8 


 

 

Six Months Ended June 30, 2008


(Millions of Dollars)

 


NU*

 


CL&P

 


PSNH

 


WMECO

 

NU
Enterprises

 

Yankee
Gas

 


Other

Net income

 

$

116.2 

 

$

89.5 

 

$

30.4 

 

$

9.6 

 

$

4.1 

 

$

17.6

 

$

(35.0)

Comprehensive (loss)/income items:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Qualified cash flow hedging instruments

 

 

(5.8)

 

 

(3.6)

 

 

(1.5)

 

 

 

 

 

 

 

 

(0.7)

  Decrease in unrealized gains on securities

 

 

(0.8)

 

 

 

 

 

 

(0.1)

 

 

 

 

 

 

(0.7)

  Pension, SERP, and other
    postretirement benefits

 

 


2.1 

 

 


 

 


 

 


 

 


1.0 

 

 


 

 


1.1 

Net change in comprehensive
   (loss)/income items

 

 


(4.5)

 

 


(3.6)

 

 


(1.5)

 

 


(0.1)

 

 


1.0 

 

 


 

 


(0.3)

Total comprehensive income/(loss)

 

$

111.7 

 

$

85.9 

 

$

28.9 

 

$

9.5 

 

$

5.1 

 

$

17.6 

 

$

(35.3)




22





 

 

Six Months Ended June 30, 2007


(Millions of Dollars)

 


NU*

 


CL&P

 


PSNH

 


WMECO

 

NU
Enterprises

 

Yankee
Gas

 


Other

Net income

 

$

123.6 

 

$

58.0 

 

$

25.2 

 

$

11.5 

 

$

7.4 

 

$

13.9 

 

$

7.6 

Comprehensive income/(loss) items:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Qualified cash flow hedging instruments

 

 

(1.6)

 

 

(1.6)

 

 

 

 

 

 

 

 

 

 

  Increase in unrealized gains on securities

 

 

1.4 

 

 

 

 

0.1 

 

 

 

 

 

 

 

 

1.3 

  Pension, SERP, and other
    postretirement benefits

 

 


6.3 

 

 


 

 


 

 


 

 


3.9 

 

 


 

 


2.4 

Net change in comprehensive
   income/(loss) items

 

 


6.1 

 

 


(1.6)

 

 


0.1 

 

 


 

 


3.9 

 

 


 

 


3.7 

Total comprehensive income

 

$

129.7 

 

$

56.4 

 

$

25.3 

 

$

11.5 

 

$

11.3 

 

$

13.9 

 

$

11.3 


*After preferred dividends of subsidiary.


Comprehensive income amounts included in the Other column primarily relate to NU parent and Northeast Utilities Service Company (NUSCO).

  

Accumulated other comprehensive income fair value adjustments in NU's qualified cash flow hedging instruments for the six months ended June 30, 2008 and the twelve months ended December 31, 2007 are as follows:



(Millions of Dollars, Net of Tax)

 

Six Months Ended
June 30, 2008

 

Twelve Months Ended
December 31, 2007

Balance at beginning of period

 

$

2.3 

 

$

5.9 

Hedged transactions recognized into earnings

 

 

0.4 

 

 

0.2 

Change in fair value of interest rate swap agreements

 

 

(6.0)

 

 

Cash flow transactions entered into for the period

 

 

(0.2)

 

 

(3.8)

Net change associated with hedging transactions

 

 

(5.8)

 

 

(3.6)

Total fair value adjustments included in accumulated
  other comprehensive income

 


$


(3.5)

 


$


2.3 


Yankee Gas has a forward interest rate swap agreement associated with its planned September 2008 long-term debt issuance.  The fair value of the interest rate swap agreement is recorded in accumulated other comprehensive income with a corresponding pre-tax amount recorded as a derivative asset/liability.  For the periods ended June 30, 2008 and December 31, 2007, a net of tax fair value benefit of $0.5 million was recorded in accumulated other comprehensive income.  For further information, see Note 2, "Derivative Instruments," to the accompanying condensed consolidated financial statements.


In March 2008, PSNH terminated an interest rate swap agreement and recorded a $2.4 million net of tax settlement charge, net of hedge ineffectiveness of $0.2 million, in accumulated other comprehensive income.


The following table provides the forward starting interest rate swap transactions entered into by the company, CL&P and PSNH to hedge interest rate risk associated with their respective long-term debt issuances and terminated in May and June, 2008:


 

 

NU Parent

 

CL&P

 

PSNH

Long-term debt issued (in millions)

 

$

250.0 

 

$

300.0 

 

$

110.0 

 

Date issued

 

 

June 5, 2008 

 

 

May 27, 2008

 

 

May 27, 2008

 

Term

 

 

5-year 

 

 

10-year 

 

 

10-year 

 

Loaded LIBOR swap percentage rate(s) (percentage)

 

 

4.102 

(1)

 

4.590 and 4.602 

(2)

 

4.5575 

(3)

Charge/(reduction) to accumulated other
  comprehensive income (net of tax) (4)

 

 


0.1 

 

 


2.3 

 

 


(1.5)

 


(1)

The interest rate swap was entered into with a notional amount of $200 million.  


(2)

The two locked rates reflect two forward starting interest rate swap transactions, each with a notional amount of $150 million.


(3)

The first swap transaction was entered into in December 2007 and was replaced at its scheduled termination date in March 2008 with a new swap to extend the hedging relationship to the revised pricing date of the long-term debt in May 2008.  


(4)

The charge to accumulated other comprehensive income will be amortized into earnings over the terms of each respective long-term debt.




23




It is estimated that a charge of $0.1 million will be reclassified from accumulated other comprehensive income as a decrease to earnings over the next 12 months as a result of amortization of amounts due to forward interest rate swap agreements that have been settled.  Assuming the fair value of the existing forward interest rate swap agreement remains unchanged from June 30, 2008 to its planned settlement date in September 2008, it is estimated that $40 thousand will be reclassified from accumulated other comprehensive income as an increase to earnings over the next 12 months as a result of amortization of amounts due to the settlement of the forward interest rate swap agreement.  At June 30, 2008, it is estimated that a pre-tax $0.1 million included in the accumulated other comprehensive income balance will be reclassified as an increase to earnings over the next 12 months related to Pension, SERP and other postretirement benefits adjustments.  


7.

DISCONTINUED OPERATIONS (NU, NU Enterprises)


NU's condensed consolidated statements of income present NGC, Mt. Tom and SECI as discontinued operations.  Under discontinued operations presentation, revenues and expenses of the businesses classified as discontinued operations are classified in loss from discontinued operations on the condensed consolidated statements of income, for all periods presented.

 

Summarized information for the discontinued operations is as follows:


 

 

For the Three Months Ended

 

For the Six Months Ended

(Millions of Dollars)

 

June 30, 2008

 

June 30, 2007

 

June 30, 2008

 

June 30, 2007

Operating revenues

 

$

 

$

0.3 

 

$

 

$

1.1 

Operating benefits/(expenses)

 

 

 

 

0.2 

 

 

 

 

(0.9)

Income from discontinued operations

 

 

 

 

0.5 

 

 

 

 

0.2 

Gain from sale/disposition of discontinued operations

 

 

 

 

3.9 

 

 

 

 

2.0 

Income tax expense from discontinued operations

 

 

 

 

(1.9)

 

 

 

 

(1.0)

Net income from discontinued operations

 

 

 

 

2.5 

 

 

 

 

1.2 


The gain on sale/disposition of discontinued operations of $3.9 million for the three months ended June 30, 2007 was primarily due to the favorable resolution of contingencies from the completion of a cogeneration plant by SESI, which was sold in May of 2006, partially offset by charges related to the sale of the competitive generation business.  In the first quarter of 2007, a $1.9 million charge resulted from a purchase price adjustment from the sale of the competitive generation business.


No intercompany revenues were included in discontinued operations for either of the three and six months ended June 30, 2008 and 2007.  


At June 30, 2008, NU did not have and does not expect to have significant ongoing involvement or continuing cash flows with the entities presented in discontinued operations.  


8.

EARNINGS PER SHARE (NU)


Earnings per share (EPS) is computed based upon the weighted average number of common shares outstanding, excluding unallocated Employee Stock Ownership Plan (ESOP) shares, during each period.  Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock.  There were no antidilutive options for any of the three- and six-month periods ended June 30, 2008 and 2007.  


The following table sets forth the components of basic and fully diluted EPS:


 

 

For the Three Months Ended June 30,

 

For the Six Months Ended June 30,

(Millions of Dollars, Except for Share Information)

 

2008

 

2007

 

2008

 

2007

Income from continuing operations

 

$

57.8 

 

$

46.0 

 

$

116.2 

 

$

122.4 

Income from discontinued operations

 

 

 

 

2.5 

 

 

 

 

1.2 

Net income

 

$

57.8 

 

$

48.5 

 

$

116.2 

 

$

123.6 

Basic EPS common shares outstanding (average)

 

 

155,476,492 

 

 

154,729,676 

 

 

155,381,302 

 

 

154,539,678 

Dilutive effect

 

 

418,856 

 

 

483,418 

 

 

427,179 

 

 

562,994 

Fully diluted EPS common shares
  outstanding (average)

 




155,895,348 

 

 


155,213,094 

 

 


155,808,481 

 

 


155,102,672 

Basic and Fully Diluted EPS:

 

 

 

 

 

 

 

 

 

 

 

 

  Income from continuing operations

 

$

0.37 

 

$

0.30 

 

$

0.75 

 

$

0.79 

  Income from discontinued operations

 

 

 

 

0.01 

 

 

 

 

0.01 

  Net income

 

$

0.37 

 

$

0.31 

 

$

0.75 

 

$

0.80 




24




Restricted share units (RSUs) are included in basic common shares outstanding when shares are both vested and issued.  The dilutive effect of RSUs granted but not issued is calculated using the treasury stock method.  Assumed proceeds of RSUs under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit.  The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the RSUs (the difference between the market value of RSUs using the average market price during the period and the grant date market value).  


The dilutive effect of stock options is also calculated using the treasury stock method.  Assumed proceeds for stock options consist of remaining compensation cost to be recognized, cash proceeds that would be received upon exercise, and a theoretical tax benefit.  The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the common shares underlying the stock options outstanding for the period using the average market price and the exercise price on the date of grant).  


Allocated ESOP shares are included in basic common shares outstanding in the above table.  


9.

LONG-TERM DEBT (NU, CL&P, PSNH)


NU parent, CL&P and PSNH issued long-term debt in the three months ended June 30, 2008.  The details of this issuance are as follows:


(Millions of Dollars)

 

 

 

Senior Notes:

 

 

 

   NU Parent:

 

 

 

      5.65% Series C due 2013

 

$

250 

First Mortgage Bonds:

 

 

 

   CL&P:

 

 

 

      5.65% 2008 Series A due 2018

 

 

300 

   PSNH:  

 

 

 

      6.00% Series O due 2018

 

 

110 

Total Long-Term Debt Issued

 

$

660 


The proceeds from the NU parent long-term debt issuance were used to repay the $150 million long-term Series B senior note with an interest rate of 3.3 percent which matured on June 1, 2008 and short-term borrowings outstanding under a credit facility.  The proceeds from the CL&P and PSNH long-term debt issuances were used to repay short-term debt, to fund each company's capital programs, and for general working capital purposes.  


These long-term debt agreements require each company to comply with certain covenants as are customarily included in such agreements.  The parties to these agreements currently are and expect to remain in compliance with these covenants.


10.

SEGMENT INFORMATION (All Companies)


Presentation: NU is organized between the regulated companies and NU Enterprises' businesses based on a combination of factors, including the characteristics of each business' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates.  Cash flows for total investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC and the capitalized portion of pension expense or income.  Segment information for all periods presented has been reclassified to conform to the current period presentation, except as indicated.  


The regulated companies segment, including the electric distribution, generation and transmission segments, as well as the gas distribution segment (Yankee Gas), represented approximately 99 percent of NU's total revenues for the three and six months ended June 30, 2008 as compared to 95 percent and 96 percent, respectively, for the 2007 periods.  CL&P's, PSNH's and WMECO's complete condensed consolidated financial statements are included in this combined quarterly report on Form 10-Q.  PSNH's distribution segment includes generation activities.  Also included in this combined quarterly report on Form 10-Q is detailed information regarding CL&P's, PSNH's, and WMECO's transmission segments.


At June 30, 2008, the NU Enterprises business segment included the following legal entities:  1) Select Energy (wholesale contracts), 2) NGS, 3) Boulos, and 4) NU Enterprises parent.  


Other in the segment tables primarily consists of 1) the results of NU parent, which include other income related to the equity in earnings of NU parent's subsidiaries and interest income from the NU Money Pool, which are both eliminated in consolidation, and interest income and expense related to the cash and debt of NU parent, respectively, 2) the revenues and expenses of Northeast



25




Utilities Services Company, most of which are eliminated in consolidation, and 3) the results of other subsidiaries, which include The Rocky River Realty Company and The Quinnehtuk Company (real estate subsidiaries), Mode 1 Communications, Inc. and the non-utility subsidiaries of Yankee Energy System, Inc. (Yankee Energy Services Company, Yankee Energy Financial Services Company and NorConn Properties, Inc.).


Effective January 1, 2007, financial information for the remaining operations of HWP that were not exited as part of the sale of the competitive generation business was included as part of the Other reportable segment as these operations were no longer considered part of NU Enterprises subsequent to the sale.  Accordingly, HWP's remaining operations have been presented as part of the Other reportable segment for each of the three and six months ended June 30, 2008 and 2007.


NU's condensed consolidated statements of income for the three and six months ended June 30, 2007 present the remaining activity for NGC, Mt. Tom and SECI as discontinued operations.  For further information and information regarding the exit from these businesses, see Note 7, "Discontinued Operations," to the condensed consolidated financial statements.


NU's segment information for the three and six months ended June 30, 2008 and 2007 is as follows (certain amounts presented in the financial statements may differ from amounts presented in the segment schedules due to rounding):


 

 

For the Three Months Ended June 30, 2008

 

 

Regulated Companies

 

 

 

 

Distribution (1)

 

 

 

 

(Millions of Dollars)

 

Electric

 

Gas

 

Transmission

 

NU Enterprises

 

Other

 

Eliminations

 

Total

Operating revenues

 

$

1,098.7 

 

$

113.0 

 

$

101.4 

 

$

30.0 

 

$

100.2 

 

$

(118.0)

 

$

1,325.3 

Depreciation and amortization

 

 

(136.9)

 

 

(6.6)

 

 

(11.6)

 

 

(0.1)

 

 

(3.1)

 

 

0.2 

 

 

(158.1)

Other operating expenses

 

 

(889.0)

 

 

(103.3)

 

 

(33.4)

 

 

(25.1)

 

 

(95.4)

 

 

117.1 

 

 

(1,029.1)

Operating income/(loss)

 

 

72.8 

 

 

3.1 

 

 

56.4 

 

 

4.8 

 

 

1.7 

 

 

(0.7)

 

 

138.1 

Interest expense, net of AFUDC

 

 

(41.6)

 

 

(4.9)

 

 

(11.8)

 

 

(1.3)

 

 

(9.1)

 

 

2.6 

 

 

(66.1)

Interest income

 

 

1.0 

 

 

 

 

1.6 

 

 

0.2 

 

 

2.3 

 

 

(3.6)

 

 

1.5 

Other income, net

 

 

1.6 

 

 

 

 

7.2 

 

 

 

 

36.4 

 

 

(36.3)

 

 

8.9 

Income tax (expense)/benefit

 

 

(6.3)

 

 

0.8 

 

 

(17.7)

 

 

(1.5)

 

 

1.9 

 

 

(0.4)

 

 

(23.2)

Preferred dividends

 

 

(0.9)

 

 

 

 

(0.5)

 

 

 

 

 

 

 

 

(1.4)

Net income

 

$

26.6 

 

$

(1.0)

 

$

35.2 

 

$

2.2 

 

$

33.2 

 

$

(38.4)

 

$

57.8 


 

 

For the Six Months Ended June 30, 2008

 

 

Regulated Companies

 

 

 

 

Distribution (1)

 

 

 

 

(Millions of Dollars)

 

Electric

 

Gas

 

Transmission

 

NU Enterprises

 

Other

 

Eliminations

 

Total

Operating revenues

 

$

2,296.8 

 

$

312.6 

 

$

196.3 

 

$

63.9 

 

$

200.1 

 

$

(224.4)

 

$

2,845.3 

Depreciation and amortization

 

 

(265.8)

 

 

(13.0)

 

 

(22.3)

 

 

(0.3)

 

 

(7.1)

 

 

0.4 

 

 

(308.1)

Other operating expenses

 

 

(1,870.7)

 

 

(261.6)

 

 

(65.1)

 

 

(54.3)

 

 

(236.1)

 

 

221.0 

 

 

(2,266.8)

Operating income/(loss)

 

 

160.3 

 

 

38.0 

 

 

108.9 

 

 

9.3 

 

 

(43.1)

 

 

(3.0)

 

 

270.4 

Interest expense, net of AFUDC

 

 

(83.2)

 

 

(10.1)

 

 

(22.2)

 

 

(3.0)

 

 

(15.0)

 

 

4.8 

 

 

(128.7)

Interest income

 

 

1.9 

 

 

 

 

2.0 

 

 

0.6 

 

 

4.0 

 

 

(5.8)

 

 

2.7 

Other income, net

 

 

8.4 

 

 

0.1 

 

 

12.6 

 

 

 

 

110.4 

 

 

(110.3)

 

 

21.2 

Income tax (expense)/benefit

 

 

(23.8)

 

 

(10.4)

 

 

(32.6)

 

 

(2.8)

 

 

24.0 

 

 

(1.0)

 

 

(46.6)

Preferred dividends

 

 

(1.8)

 

 

 

 

(1.0)

 

 

 

 

 

 

 

 

(2.8)

Net income

 

$

61.8 

 

$

17.6 

 

$

67.7 

 

$

4.1 

 

$

80.3 

 

$

(115.3)

 

$

116.2 

Total assets (2)

 

$

11,160.0 

 

$

1,280.8 

 

$

 

$

111.3 

 

$

4,232.2 

 

$

(4,075.0)

 

$

12,709.3 

Cash flows for total
  investments in plant

 

$


205.5 

 

$


23.4 

 

$


383.6 

 

$


 

$


12.6 

 


$


 


$


625.1 


 

 

For the Three Months Ended June 30, 2007

 

 

Regulated Companies

 

 

 

 

Distribution (1)

 

 

 

 

(Millions of Dollars)

 

Electric

 

Gas

 

Transmission

 

NU Enterprises

 

Other

 

Eliminations

 

Total

Operating revenues

 

$

1,160.0 

 

$

95.0 

 

$

73.0 

 

$

72.2 

 

$

99.9 

 

$

(108.3)

 

$

1,391.8 

Depreciation and amortization

 

 

(90.9)

 

 

(5.8)

 

 

(9.2)

 

 

(0.1)

 

 

(1.7)

 

 

0.7 

 

 

(107.0)

Other operating expenses

 

 

(998.0)

 

 

(85.2)

 

 

(27.1)

 

 

(70.6)

 

 

(93.7)

 

 

106.6 

 

 

(1,168.0)

Operating income

 

 

71.1 

 

 

4.0 

 

 

36.7 

 

 

1.5 

 

 

4.5 

 

 

 (1.0)

 

 

116.8 

Interest expense, net of AFUDC

 

 

(41.4)

 

 

(4.2)

 

 

(8.3)

 

 

(2.3)

 

 

(8.9)

 

 

5.5 

 

 

(59.6)

Interest income

 

 

1.0 

 

 

 

 

0.7 

 

 

0.8 

 

 

7.6 

 

 

(5.4)

 

 

4.7 

Other income, net

 

 

3.8 

 

 

0.5 

 

 

2.6 

 

 

 

 

29.5 

 

 

(29.2)

 

 

7.2 

Income tax expense

 

 

(10.5)

 

 

 

 

(10.1)

 

 

 

 

(0.5)

 

 

(0.6)

 

 

(21.7)

Preferred dividends

 

 

(0.9)

 

 

 

 

(0.5)

 

 

 

 

 

 

 

 

(1.4)

Income from
  continuing operations

 

 


23.1 

 

 


0.3 

 

 


21.1 

 

 


 

 


32.2 

 




(30.7)

 




46.0 

Income from
  discontinued operations

 

 


 

 


 

 


 

 


2.5 

 

 


 

 


 

 


2.5 

Net income

 

$

23.1 

 

$

0.3 

 

$

21.1 

 

$

2.5 

 

$

32.2 

 

$

(30.7)

 

$

48.5 




26





 

 

For the Six Months Ended June 30, 2007

 

 

Regulated Companies

 

 

 

 

Distribution (1)

 

 

 

 

(Millions of Dollars)

 

Electric

 

Gas

 

Transmission

 

NU Enterprises

 

Other

 

Eliminations

 

Total

Operating revenues

 

$

2,541.4 

 

$

279.8 

 

$

141.8 

 

$

152.1 

 

$

193.9 

 

$

(213.7)

 

$

3,095.3 

Depreciation and amortization

 

 

(196.1)

 

 

(11.6)

 

 

(18.2)

 

 

(0.3)

 

 

(4.1)

 

 

1.7 

 

 

(228.6)

Other operating expenses

 

 

(2,187.2)

 

 

(239.6)

 

 

(55.4)

 

 

(140.1)

 

 

(181.7)

 

 

209.8 

 

 

(2,594.2)

Operating income

 

 

158.1 

 

 

28.6 

 

 

68.2 

 

 

11.7 

 

 

8.1 

 

 

(2.2)

 

 

272.5 

Interest expense, net of AFUDC

 

 

(83.8)

 

 

(8.5)

 

 

(17.1)

 

 

(5.3)

 

 

(17.1)

 

 

12.9 

 

 

(118.9)

Interest income

 

 

2.0 

 

 

 

 

1.1 

 

 

1.3 

 

 

20.3 

 

 

(12.8)

 

 

11.9 

Other income, net

 

 

8.0 

 

 

1.0 

 

 

3.9 

 

 

 

 

86.0 

 

 

(84.8)

 

 

14.1 

Income tax expense

 

 

(24.6)

 

 

(7.2)

 

 

(18.3)

 

 

(1.5)

 

 

(1.7)

 

 

(1.1)

 

 

(54.4)

Preferred dividends

 

 

(2.0)

 

 

 

 

(0.8)

 

 

 

 

 - 

 

 

 

 

(2.8)

Income from
  continuing operations

 

 


57.7 

 

 


13.9 

 

 


37.0 

 

 


6.2 

 

 


95.6 

 

 


(88.0)

 

 


122.4 

Income from
  discontinued operations

 

 


 

 


 

 


 

 


1.2 

 

 


 

 


 

 


1.2 

Net income

 

$

57.7 

 

$

13.9 

 

$

37.0 

 

$

7.4 

 

$

95.6 

 

$

(88.0)

 

$

123.6 

Cash flows for total
 investments in plant

 

$


184.4 

 

$


29.2 

 

$


270.2 

 

$


1.2 

 

$


6.1 

 


$


 


$


491.1 


(1)

Includes PSNH's generation activities.


(2)

Information for segmenting total assets between electric distribution and transmission is not available at June 30, 2008.  On an NU consolidated basis, these distribution and transmission assets are disclosed in the electric distribution columns above.


The regulated companies information related to the distribution and transmission segments for CL&P, PSNH and WMECO for the three and six months ended June 30, 2008 and 2007 is as follows:


 

 

CL&P - For the Three Months Ended June 30, 2008

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

741.7 

 

$

80.2 

 

821.9 

Depreciation and amortization

 

 

(120.8)

 

 

(9.2)

 

 

(130.0)

Other operating expenses

 

 

(579.4)

 

 

(22.9)

 

 

(602.3)

Operating income

 

 

41.5 

 

 

48.1 

 

 

89.6 

Interest expense, net of AFUDC

 

 

(26.3)

 

 

(10.1)

 

 

(36.4)

Interest income

 

 

0.7 

 

 

1.0 

 

 

1.7 

Other income, net

 

 

1.5 

 

 

6.4 

 

 

7.9 

Income tax expense

 

 

(1.7)

 

 

(14.9)

 

 

(16.6)

Preferred dividends

 

 

(0.9)

 

 

(0.5)

 

 

(1.4)

Net income

 

$

14.8 

 

$

30.0 

 

$

44.8 


 

 

CL&P - For the Six Months Ended June 30, 2008

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

1,553.8 

 

$

153.6 

 

1,707.4 

Depreciation and amortization

 

 

(208.8)

 

 

(17.6)

 

 

(226.4)

Other operating expenses

 

 

(1,255.0)

 

 

(46.6)

 

 

(1,301.6)

Operating income

 

 

90.0 

 

 

89.4 

 

 

179.4 

Interest expense, net of AFUDC

 

 

(52.6)

 

 

(18.8)

 

 

(71.4)

Interest income

 

 

1.3 

 

 

1.4 

 

 

2.7 

Other income, net

 

 

7.9 

 

 

11.2 

 

 

19.1 

Income tax expense

 

 

(11.1)

 

 

(26.4)

 

 

(37.5)

Preferred dividends

 

 

(1.8)

 

 

(1.0)

 

 

(2.8)

Net income

 

$

33.7 

 

$

55.8 

 

89.5 

Cash flows for total investments in plant

 

$

119.4 

 

$

322.6 

 

$

442.0 




27





 

 

CL&P - For the Three Months Ended June 30, 2007

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

814.2 

 

$

56.2 

 

870.4 

Depreciation and amortization

 

 

(72.1)

 

 

(7.1)

 

 

(79.2)

Other operating expenses

 

 

(708.0)

 

 

(19.2)

 

 

(727.2)

Operating income

 

 

34.1 

 

 

29.9 

 

 

64.0 

Interest expense, net of AFUDC

 

 

(26.0)

 

 

(6.9)

 

 

(32.9)

Interest income

 

 

0.7 

 

 

0.5 

 

 

1.2 

Other income, net

 

 

3.2 

 

 

2.4 

 

 

5.6 

Income tax expense

 

 

(4.1)

 

 

(8.0)

 

 

(12.1)

Preferred dividends

 

 

(0.9)

 

 

(0.5)

 

 

(1.4)

Net income

 

$

7.0 

 

$

17.4 

 

24.4 


 

 

CL&P - For the Six Months Ended June 30, 2007

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

1,805.5 

 

$

108.6 

 

1,914.1 

Depreciation and amortization

 

 

(138.6)

 

 

(14.1)

 

 

(152.7)

Other operating expenses

 

 

(1,579.2)

 

 

(39.3)

 

 

(1,618.5)

Operating income

 

 

87.7 

 

 

55.2 

 

 

142.9 

Interest expense, net of AFUDC

 

 

(53.9)

 

 

(14.1)

 

 

(68.0)

Interest income

 

 

1.4 

 

 

0.9 

 

 

2.3 

Other income, net

 

 

7.0 

 

 

3.5 

 

 

10.5 

Income tax expense

 

 

(12.6)

 

 

(14.3)

 

 

(26.9)

Preferred dividends

 

 

(2.0)

 

 

(0.8)

 

 

(2.8)

Net income

 

$

27.6 

 

$

30.4 

 

58.0 

Cash flows for total investments in plant

 

$

112.6 

 

$

240.6 

 

$

353.2 


 

 

PSNH - For the Three Months Ended June 30, 2008

(Millions of Dollars)

 

Distribution (1)

 

Transmission

 

Total

Operating revenues

 

$

259.2 

 

$

14.8 

 

274.0 

Depreciation and amortization

 

 

(4.5)

 

 

(1.8)

 

 

(6.3)

Other operating expenses

 

 

(230.7)

 

 

(7.0)

 

 

(237.7)

Operating income

 

 

24.0 

 

 

6.0 

 

 

30.0 

Interest expense, net of AFUDC

 

 

(10.9)

 

 

(1.2)

 

 

(12.1)

Interest income

 

 

0.2 

 

 

0.4 

 

 

0.6 

Other income, net

 

 

0.2 

 

 

0.5 

 

 

0.7 

Income tax expense

 

 

(3.4)

 

 

(2.1)

 

 

(5.5)

Net income

 

$

10.1 

 

$

3.6 

 

13.7 


 

 

PSNH - For the Six Months Ended June 30, 2008

(Millions of Dollars)

 

Distribution (1)

 

Transmission

 

Total

Operating revenues

 

$

535.9 

 

$

29.9 

 

565.8 

Depreciation and amortization

 

 

(34.7)

 

 

(3.4)

 

 

(38.1)

Other operating expenses

 

 

(450.5)

 

 

(12.3)

 

 

(462.8)

Operating income

 

 

50.7 

 

 

14.2 

 

 

64.9 

Interest expense, net of AFUDC

 

 

(21.8)

 

 

(2.3)

 

 

(24.1)

Interest income

 

 

0.3 

 

 

0.4 

 

 

0.7 

Other income, net

 

 

0.6 

 

 

1.3 

 

 

1.9 

Income tax expense

 

 

(8.2)

 

 

(4.8)

 

 

(13.0)

Net income

 

$

21.6 

 

$

8.8 

 

30.4 

Cash flows for total investments in plant

 

$

71.6 

 

$

47.6 

 

$

119.2 




28





 

 

PSNH - For the Three Months Ended June 30, 2007

(Millions of Dollars)

 

Distribution (1)

 

Transmission

 

Total

Operating revenues

 

$

239.1 

 

$

11.1 

 

250.2 

Depreciation and amortization

 

 

(9.1)

 

 

(1.4)

 

 

(10.5)

Other operating expenses

 

 

(203.2)

 

 

(4.9)

 

 

(208.1)

Operating income

 

 

26.8 

 

 

4.8 

 

 

31.6 

Interest expense, net of AFUDC

 

 

(10.6)

 

 

(1.0)

 

 

(11.6)

Interest income

 

 

0.1 

 

 

0.1 

 

 

0.2 

Other income, net

 

 

0.3 

 

 

0.1 

 

 

0.4 

Income tax expense

 

 

(4.0)

 

 

(1.4)

 

 

(5.4)

Net income

 

$

12.6 

 

$

2.6 

 

15.2 


 

 

PSNH - For the Six Months Ended June 30, 2007

(Millions of Dollars)

 

Distribution (1)

 

Transmission

 

Total

Operating revenues

 

$

505.3 

 

$

22.0 

 

527.3 

Depreciation and amortization

 

 

(37.7)

 

 

(2.8)

 

 

(40.5)

Other operating expenses

 

 

(420.7)

 

 

(10.5)

 

 

(431.2)

Operating income

 

 

46.9 

 

 

8.7 

 

 

55.6 

Interest expense, net of AFUDC

 

 

(21.0)

 

 

(2.1)

 

 

(23.1)

Interest income

 

 

0.3 

 

 

0.1 

 

 

0.4 

Other income, net

 

 

0.6 

 

 

0.4 

 

 

1.0 

Income tax expense

 

 

(6.1)

 

 

(2.6)

 

 

(8.7)

Net income

 

$

20.7 

 

$

4.5 

 

25.2 

Cash flows for total investments in plant

 

$

56.8 

 

$

22.7 

 

$

79.5 


 (1)

Includes PSNH's generation activities.  


 

 

WMECO - For the Three Months Ended June 30, 2008

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

97.8 

 

$

6.4 

 

104.2 

Depreciation and amortization

 

 

(11.6)

 

 

(0.7)

 

 

(12.3)

Other operating expenses

 

 

(79.0)

 

 

(3.3)

 

 

(82.3)

Operating income

 

 

7.2 

 

 

2.4 

 

 

9.6 

Interest expense, net of AFUDC

 

 

(4.4)

 

 

(0.4)

 

 

(4.8)

Interest income

 

 

0.2 

 

 

0.2 

 

 

0.4 

Other income, net

 

 

 

 

0.1 

 

 

0.1 

Income tax expense

 

 

(1.3)

 

 

(0.7)

 

 

(2.0)

Net income

 

$

1.7 

 

$

1.6 

 

3.3 


 

 

WMECO - For the Six Months Ended June 30, 2008

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

207.3 

 

$

12.7 

 

220.0 

Depreciation and amortization

 

 

(22.4)

 

 

(1.3)

 

 

(23.7)

Other operating expenses

 

 

(165.4)

 

 

(6.1)

 

 

(171.5)

Operating income

 

 

19.5 

 

 

5.3 

 

 

24.8 

Interest expense, net of AFUDC

 

 

(8.8)

 

 

(1.2)

 

 

(10.0)

Interest income

 

 

0.3 

 

 

0.3 

 

 

0.6 

Other income, net

 

 

 

 

0.2 

 

 

0.2 

Income tax expense

 

 

(4.5)

 

 

(1.5)

 

 

(6.0)

Net income

 

$

6.5 

 

$

3.1 

 

9.6 

Cash flows for total investments in plant

 

$

14.6 

 

$

13.3 

 

27.9 




29





 

 

WMECO - For the Three Months Ended June 30, 2007

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

106.7 

 

$

5.7 

 

112.4 

Depreciation and amortization

 

 

(9.6)

 

 

(0.7)

 

 

(10.3)

Other operating expenses

 

 

(86.8)

 

 

(3.0)

 

 

(89.8)

Operating income

 

 

10.3 

 

 

2.0 

 

 

12.3 

Interest expense, net of AFUDC

 

 

(4.7)

 

 

(0.4)

 

 

(5.1)

Interest income

 

 

0.1 

 

 

0.1 

 

 

0.2 

Other income, net

 

 

0.2 

 

 

0.1 

 

 

0.3 

Income tax expense

 

 

(2.4)

 

 

(0.7)

 

 

(3.1)

Net income

 

$

3.5 

 

$

1.1 

 

4.6 


 

 

WMECO - For the Six Months Ended June 30, 2007

(Millions of Dollars)

 

Distribution

 

Transmission

 

Total

Operating revenues

 

$

230.6 

 

$

11.3 

 

241.9 

Depreciation and amortization

 

 

(19.8)

 

 

(1.3)

 

 

(21.1)

Other operating expenses

 

 

(187.4)

 

 

(5.7)

 

 

(193.1)

Operating income

 

 

23.4 

 

 

4.3 

 

 

27.7 

Interest expense, net of AFUDC

 

 

(8.9)

 

 

(0.9)

 

 

(9.8)

Interest income

 

 

0.3 

 

 

0.1 

 

 

0.4 

Other income, net

 

 

0.5 

 

 

 

 

0.5 

Income tax expense

 

 

(5.9)

 

 

(1.4)

 

 

(7.3)

Net income

 

$

9.4 

 

$

2.1 

 

$

11.5 

Cash flows for total investments in plant

 

$

15.0 

 

$

6.9 

 

21.9 



30




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Trustees and Shareholders of Northeast Utilities:


We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries (the "Company") as of June 30, 2008, and the related condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2008 and 2007, and of cash flows for the six-month periods ended June 30, 2008 and 2007.  These interim financial statements are the responsibility of the Company’s management.


We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.


Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.


As discussed in Notes 1.C. and 3., the Company adopted Statement of Financial Accounting Standard No. 157, Fair Value Measurements , as of January 1, 2008.


We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and consolidated statement of capitalization of Northeast Utilities and subsidiaries as of December 31, 2007, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated February 28, 2008 (which report included an explanatory paragraph related to the adoption of Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109 , as of January 1, 2007), we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2007 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.



/s/

Deloitte & Touche LLP

 

Deloitte & Touche LLP



Hartford, Connecticut

August 6, 2008




31




This Page Intentionally Left Blank



32




THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES



33





THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

 

 

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

June 30,

 

 

December 31,

 

 

2008

 

 

2007

 

 

(Thousands of Dollars)

ASSETS

 

 

 

 

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

  Cash

 

$                        17 

 

 

$                      538 

  Investments in securitizable assets (Note 1E)

 

 

 

308,182 

  Receivables, less provision for uncollectible

 

 

 

 

 

    accounts of $20,787 in 2008 and $7,874 in 2007

 

348,544 

 

 

118,342 

  Accounts receivable from affiliated companies

 

8,798 

 

 

3,339 

  Unbilled revenues

 

117,906 

 

 

8,225 

  Taxes receivable

 

 

 

16,245 

  Materials and supplies

 

66,041 

 

 

55,477 

  Derivative assets - current

 

90,013 

 

 

57,003 

  Prepayments and other

 

9,514 

 

 

17,387 

 

 

640,833 

 

 

584,738 

 

 

 

 

 

 

Property, Plant and Equipment:

 

 

 

 

 

  Electric utility

 

5,189,098 

 

 

4,899,075 

     Less: Accumulated depreciation

 

1,318,485 

 

 

1,279,697 

 

 

3,870,613 

 

 

3,619,378 

  Construction work in progress

 

926,880 

 

 

782,468 

 

 

4,797,493 

 

 

4,401,846 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

  Regulatory assets

 

1,778,353 

 

 

1,329,963 

  Prepaid pension

 

351,517 

 

 

334,786 

  Derivative assets - long-term

 

392,777 

 

 

278,726 

  Other

 

75,222 

 

 

88,040 

 

 

2,597,869 

 

 

2,031,515 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

 

$            8,036,195 

 

 

$            7,018,099 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 

 




34





THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

 

 

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

June 30,

 

 

December 31,

 

 

2008

 

 

2007

 

 

(Thousands of Dollars)

LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

  Notes payable to affiliated companies

 

$              52,325 

 

 

$              38,825 

  Accounts payable

 

369,577 

 

 

368,356 

  Accounts payable to affiliated companies

 

41,801 

 

 

53,096 

  Accrued taxes

 

24,707 

 

 

  Accrued interest

 

33,444 

 

 

29,532 

  Derivative liabilities - current

 

2,113 

 

 

4,234 

  Counterparty deposits

 

24,825 

 

 

  Other

 

119,336 

 

 

107,940 

 

 

668,128 

 

 

601,983 

 

 

 

 

 

 

Rate Reduction Bonds

 

464,746 

 

 

548,686 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

  Accumulated deferred income taxes

 

761,364 

 

 

698,789 

  Accumulated deferred investment tax credits

 

20,109 

 

 

21,412 

  Deferred contractual obligations

 

141,485 

 

 

152,735 

  Regulatory liabilities

 

599,789 

 

 

601,455 

  Derivative liabilities - long-term

 

725,613 

 

 

135,991 

  Accrued postretirement benefits

 

74,066 

 

 

78,587 

  Other

 

201,744 

 

 

191,464 

 

 

2,524,170 

 

 

1,880,433 

Capitalization:

 

 

 

 

 

  Long-Term Debt

 

2,330,694 

 

 

2,028,546 

 

 

 

 

 

 

  Preferred Stock - Non-Redeemable

 

116,200 

 

 

116,200 

 

 

 

 

 

 

  Common Stockholder's Equity:

 

 

 

 

 

    Common stock, $10 par value - authorized

 

 

 

 

 

      24,500,000 shares; 6,035,205 shares outstanding

 

 

 

 

 

      in 2008 and 2007

 

60,352 

 

 

60,352 

    Capital surplus, paid in

 

1,301,226 

 

 

1,243,940 

    Retained earnings

 

574,451 

 

 

538,138 

    Accumulated other comprehensive loss

 

(3,772)

 

 

(179)

  Common Stockholder's Equity

 

1,932,257 

 

 

1,842,251 

Total Capitalization

 

4,379,151 

 

 

3,986,997 

 

 

 

 

 

 

Commitments and Contingencies (Note 5)

 

 

 

 

 

.

 

 

 

 

 

Total Liabilities and Capitalization

 

$         8,036,195 

 

 

$         7,018,099 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 

 




35





THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

 

 

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

June 30,

 

June 30,

 

 

2008

 

2007

 

2008

 

2007

 

(Thousands of Dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

$          821,875 

 

$          870,379 

 

$       1,707,374 

 

$       1,914,065 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

  Operation -

 

 

 

 

 

 

 

 

     Fuel, purchased and net interchange power

 

398,085 

 

516,270 

 

891,893 

 

1,205,043 

     Other

 

132,329 

 

143,664 

 

261,372 

 

277,238 

  Maintenance

 

33,154 

 

29,456 

 

62,434 

 

50,890 

  Depreciation

 

39,855 

 

38,293 

 

78,724 

 

76,482 

  Amortization of regulatory assets, net

 

56,404 

 

9,649 

 

75,988 

 

9,319 

  Amortization of rate reduction bonds

 

33,649 

 

31,268 

 

71,680 

 

66,929 

  Taxes other than income taxes

 

38,764 

 

37,828 

 

85,834 

 

85,249 

    Total operating expenses

 

732,240 

 

806,428 

 

1,527,925 

 

1,771,150 

Operating Income

 

89,635 

 

63,951 

 

179,449 

 

142,915 

 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

 

  Interest on long-term debt

 

25,392 

 

21,564 

 

48,999 

 

39,180 

  Interest on rate reduction bonds

 

7,595 

 

9,747 

 

15,811 

 

19,867 

  Other interest

 

3,404 

 

1,630 

 

6,561 

 

8,952 

    Interest expense, net

 

36,391 

 

32,941 

 

71,371 

 

67,999 

Other Income, Net

 

9,575 

 

6,879 

 

21,698 

 

12,730 

Income Before Income Tax Expense

 

62,819 

 

37,889 

 

129,776 

 

87,646 

Income Tax Expense

 

16,564 

 

12,103 

 

37,453 

 

26,866 

Net Income

 

$            46,255 

 

$            25,786 

 

$            92,323 

 

$            60,780 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 




36





THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

Six Months Ended

 

 

June 30,

 

 

2008

 

 

2007

 

 

(Thousands of Dollars)

Operating Activities:

 

 

 

 

 

Net income

$

92,323 

 

$

60,780 

Adjustments to reconcile to net cash flows

 

 

 

 

 

  provided by operating activities:

 

 

 

 

 

Bad debt expense

 

3,042 

 

 

9,699 

Depreciation

 

78,724 

 

 

76,482 

Deferred income taxes

 

49,945 

 

 

 (13,111)

Pension income, net of capitalized portion

 

 (5,681)

 

 

 (4,097)

Amortization of recoverable energy costs

 

      - 

 

 

2,064 

Amortization of rate reduction bonds

 

71,680 

 

 

66,929 

Amortization of regulatory assets, net

 

75,988 

 

 

9,319 

Regulatory (refunds and underrecoveries)/overrecoveries

 

 (133,161)

 

 

41,371 

Settlement of cash flow hedge instruments

 

 (3,890)

 

 

       - 

Deferred contractual obligations

 

 (11,250)

 

 

 (15,762)

Other non-cash adjustments

 

 (12,301)

 

 

 (7,442)

Other uses of cash

 

 (7,297)

 

 

 (11,915)

Changes in current assets and liabilities:

 

 

 

 

 

Receivables and unbilled revenues, net

 

 (18,814)

 

 

 (8,708)

Materials and supplies

 

 (10,569)

 

 

 (7,996)

Investments in securitizable assets

 

 (25,787)

 

 

17,675 

Other current assets

 

7,794 

 

 

4,440 

Accounts payable

 

 (21,439)

 

 

(18,242)

Taxes receivable/accrued

 

47,209 

 

 

 (150,041)

Counterparty deposits

 

24,825 

 

 

Other current liabilities

 

6,586 

 

 

6,938 

Net cash flows provided by operating activities

 

207,927 

 

 

58,383 

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

Investments in property and plant

 

 (442,014)

 

 

 (353,241)

Proceeds from sales of investment securities

 

1,322 

 

 

858 

Purchases of investment securities

 

 (1,353)

 

 

 (896)

Rate reduction bond escrow and other deposits

 

5,643 

 

 

5,128 

Other investing activities

 

623 

 

 

648 

Net cash flows used in investing activities

 

 (435,779)

 

 

 (347,503)

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

Issuance of long-term debt

 

300,000 

 

 

300,000 

Retirement of rate reduction bonds

 

 (83,940)

 

 

 (77,796)

Increase/(decrease) in NU Money Pool borrowings

 

13,500 

 

 

 (102,200)

Capital contributions from NU parent

 

57,058 

 

 

215,000 

Cash dividends on preferred stock

 

 (2,779)

 

 

 (2,779)

Cash dividends on common stock

 

 (53,231)

 

 

 (39,591)

Other financing activities

 

 (3,277)

 

 

 (4,818)

Net cash flows provided by financing activities

 

227,331 

 

 

287,816 

Net decrease in cash

 

 (521)

 

 

 (1,304)

Cash - beginning of period

 

538 

 

 

3,310 

Cash - end of period

$

17 

 

2,006 

 

 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.





37




This Page Intentionally Left Blank



38





PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE



39





PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

(Unaudited)

 

 

 

 

June 30,

 

December 31,

 

2008

 

2007

 

(Thousands of Dollars)

ASSETS

 

 

 

 

 

 

 

Current Assets:

 

 

 

  Cash

$                     224 

 

$                     450 

  Receivables, less provision for uncollectible

 

 

 

    accounts of $3,201 in 2008 and $2,675 in 2007

85,787 

 

97,749 

  Accounts receivable from affiliated companies

5,564 

 

817 

  Unbilled revenues

50,626 

 

45,607 

  Notes receivable from affiliated companies

16,200 

 

  Taxes receivable

37,335 

 

255 

  Fuel, materials and supplies

81,891 

 

72,215 

  Derivative assets - current

64,778 

 

6,146 

  Prepayments and other

15,322 

 

14,327 

 

357,727 

 

237,566 

 

 

 

 

Property, Plant and Equipment:

 

 

 

  Electric utility

2,132,769 

 

2,010,220 

     Less: Accumulated depreciation

759,136 

 

737,917 

 

1,373,633 

 

1,272,303 

  Construction work in progress

95,325 

 

116,102 

 

1,468,958 

 

1,388,405 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

  Regulatory assets

374,076 

 

401,374 

  Derivative assets - long-term

27,984 

 

12,075 

  Other

64,676 

 

67,549 

 

466,736 

 

480,998 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

$           2,293,421 

 

$           2,106,969 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 




40





PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

(Unaudited)

 

 

 

 

June 30,

 

December 31,

 

2008

 

2007

 

(Thousands of Dollars)

LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

  Notes payable to banks

$                        - 

 

$                 10,000 

  Notes payable to affiliated companies

 

11,300 

  Accounts payable

84,994 

 

91,356 

  Accounts payable to affiliated companies

19,032 

 

15,717 

  Accrued interest

9,850 

 

9,175 

  Derivative liabilities - current

 

2,453 

  Other

50,347 

 

22,664 

 

164,223 

 

162,665 

 

 

 

 

Rate Reduction Bonds

257,638 

 

282,018 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

  Accumulated deferred income taxes

169,508 

 

192,094 

  Accumulated deferred investment tax credits

468 

 

582 

  Deferred contractual obligations

25,525 

 

28,215 

  Regulatory liabilities

185,428 

 

127,569 

  Accrued pension

144,001 

 

138,346 

  Accrued postretirement benefits

27,765 

 

29,057 

  Other

47,965 

 

31,559 

 

600,660 

 

547,422 

Capitalization:

 

 

 

  Long-Term Debt

686,753 

 

576,997 

 

 

 

 

  Common Stockholder's Equity:

 

 

 

    Common stock, $1 par value - authorized

 

 

 

     100,000,000 shares; 301 shares outstanding

 

 

 

     in 2008 and 2007

 

    Capital surplus, paid in

311,159 

 

275,569 

    Retained earnings

273,720 

 

261,528 

    Accumulated other comprehensive (loss)/income

 (732)

 

770 

  Common Stockholder's Equity

584,147 

 

537,867 

Total Capitalization

1,270,900 

 

1,114,864 

 

 

 

 

 

 

 

 

Commitments and Contingencies (Note 5)

 

 

 

 

 

 

 

Total Liabilities and Capitalization

$          2,293,421 

 

$            2,106,969 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 




41






PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2008

 

2007

 

2008

 

2007

 

(Thousands of Dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

$           274,039 

 

$            250,233 

 

$            565,804 

 

$           527,329 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

  Operation -

 

 

 

 

 

 

 

     Fuel, purchased and net interchange power

142,534 

 

126,187 

 

284,435 

 

268,612 

     Other

55,861 

 

49,488 

 

109,107 

 

102,539 

  Maintenance

29,283 

 

22,708 

 

49,173 

 

40,112 

  Depreciation

13,720 

 

13,354 

 

27,222 

 

26,643 

  Amortization of regulatory liabilities, net

 (18,319)

 

 (15,503)

 

 (11,911)

 

 (11,709)

  Amortization of rate reduction bonds

10,870 

 

12,697 

 

22,747 

 

25,603 

  Taxes other than income taxes

10,045 

 

9,734 

 

20,121 

 

19,884 

    Total operating expenses

243,994 

 

218,665 

 

500,894 

 

471,684 

Operating Income

30,045 

 

31,568 

 

64,910 

 

55,645 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

  Interest on long-term debt

7,721 

 

6,254 

 

14,999 

 

12,405 

  Interest on rate reduction bonds

4,081 

 

4,603 

 

8,232 

 

9,311 

  Other interest

332 

 

787 

 

890 

 

1,380 

    Interest expense, net

12,134 

 

11,644 

 

24,121 

 

23,096 

Other Income, Net

1,262 

 

720 

 

2,588 

 

1,393 

Income Before Income Tax Expense

19,173 

 

20,644 

 

43,377 

 

33,942 

Income Tax Expense

5,482 

 

5,399 

 

12,997 

 

8,730 

Net Income

$             13,691 

 

$              15,245 

 

$              30,380 

 

$             25,212 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 

 

 




42





PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

 

(Unaudited)

 

 

 

 

 

 

 

Six Months Ended

 

 

June 30,

 

 

2008

 

 

2007

 

 

(Thousands of Dollars)

Operating activities:

 

 

 

 

 

Net income

$

30,380 

 

$

25,212 

Adjustments to reconcile to net cash flows

 

 

 

 

 

  provided by operating activities:

 

 

 

 

 

Bad debt expense

 

2,523 

 

 

1,407 

Depreciation

 

27,222 

 

 

26,643 

Deferred income taxes

 

4,144 

 

 

58 

Pension expense, net of capitalized portion

 

6,796 

 

 

7,718 

Amortization of rate reduction bonds

 

22,747 

 

 

25,603 

Amortization of regulatory liabilities, net

 

(11,911)

 

 

 (11,709)

Regulatory refunds and underrecoveries

 

(545)

 

 

 (3,473)

Net settlement of cash flow hedge instruments

 

(1,730)

 

 

Deferred contractual obligations

 

(2,690)

 

 

 (3,463)

Other non-cash adjustments

 

(3,789)

 

 

 (2,967)

Other uses of cash

 

(5,176)

 

 

 (11,730)

Changes in current assets and liabilities:

 

 

 

 

 

Receivables and unbilled revenues, net

 

(327)

 

 

4,312 

Taxes receivable/accrued

 

(24,739)

 

 

 (13,583)

Fuel, materials and supplies

 

(9,676)

 

 

7,892 

Other current assets

 

870 

 

 

 (5,739)

Accounts payable

 

15,293 

 

 

2,105 

Other current liabilities

 

2,749 

 

 

4,291 

Net cash flows provided by operating activities

 

52,141 

 

 

52,577 

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

Investments in property and plant

 

(119,208)

 

 

 (79,470)

Increase in NU Money Pool lending

 

(16,200)

 

 

Proceeds from sales of investment securities

 

2,265 

 

 

1,471 

Purchases of investment securities

 

(2,319)

 

 

(1,536)

Other investing activities

 

3,007 

 

 

1,779 

Net cash flows used in investing activities

 

(132,455)

 

 

(77,756)

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

    Issuance of long-term debt

 

110,000 

 

 

Decrease in short-term debt

 

(10,000)

 

 

Retirement of rate reduction bonds

 

(24,380)

 

 

(25,527)

(Decrease)/increase in NU Money Pool borrowings

 

 (11,300)

 

 

36,700 

Capital contributions from NU parent

 

35,500 

 

 

29,500 

Cash dividends on common stock

 

 (18,188)

 

 

 (15,359)

Other financing activities

 

 (1,544)

 

 

 (83)

Net cash flows provided by financing activities

 

80,088 

 

 

25,231 

Net (decrease)/increase in cash

 

(226)

 

 

52 

Cash - beginning of period

 

450 

 

 

31 

Cash - end of period

$

224 

 

$

83 

 

 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.





43




This Page Intentionally Left Blank



44




WESTERN MASSACHUSETTS ELECTRIC COMPANY



45





WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

 

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30,

 

 

December 31,

 

 

2008

 

 

2007

 

(Thousands of Dollars)

ASSETS

 

 

 

 

 

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

  Cash

 

$                2,094 

 

 

$                1,110 

  Receivables, less provision for uncollectible

 

 

 

 

 

    accounts of $6,744 in 2008 and $5,699 in 2007

 

48,622 

 

 

49,578 

  Accounts receivable from affiliated companies

 

2,727 

 

 

258 

  Unbilled revenues

 

16,086 

 

 

17,990 

  Taxes receivable

 

15,885 

 

 

3,382 

  Materials and supplies

 

3,319 

 

 

2,353 

  Marketable securities - current

 

44,863 

 

 

31,286 

  Prepayments and other

 

4,371 

 

 

2,661 

 

 

137,967 

 

 

108,618 

 

 

 

 

 

 

Property, Plant and Equipment:

 

 

 

 

 

  Electric utility

 

749,835 

 

 

728,712 

     Less: Accumulated depreciation

 

211,834 

 

 

205,743 

 

 

538,001 

 

 

522,969 

  Construction work in progress

 

42,846 

 

 

36,388 

 

 

580,847 

 

 

559,357 

 

 

 

 

 

 

Deferred Debits and Other Assets:

 

 

 

 

 

  Regulatory assets

 

173,878 

 

 

193,921 

  Prepaid pension

 

93,804 

 

 

90,015 

  Marketable securities - long-term

 

11,854 

 

 

25,078 

  Other

 

14,234 

 

 

14,099 

 

 

293,770 

 

 

323,113 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

 

$         1,012,584 

 

 

$            991,088 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 

 




46





WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

 

 

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30,

 

 

December 31,

 

 

2008

 

2007

 

 

(Thousands of Dollars)

LIABILITIES AND CAPITALIZATION

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

  Notes payable to affiliated companies

 

$                 3,300 

 

 

$                14,900 

  Accounts payable

 

32,147 

 

 

30,636 

  Accounts payable to affiliated companies

 

10,062 

 

 

7,480 

  Accrued interest

 

5,418 

 

 

5,498 

  Counterparty deposits

 

9,019 

 

 

  Other

 

10,904 

 

 

10,489 

 

 

70,850 

 

 

69,003 

 

 

 

 

 

 

Rate Reduction Bonds

 

79,876 

 

 

86,731 

 

 

 

 

 

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

  Accumulated deferred income taxes

 

188,245 

 

 

187,139 

  Accumulated deferred investment tax credits

 

1,884 

 

 

2,015 

  Deferred contractual obligations

 

38,925 

 

 

41,958 

  Regulatory liabilities

 

36,369 

 

 

39,437 

  Accrued postretirement benefits

 

11,855 

 

 

12,668 

  Other

 

17,273 

 

 

5,015 

 

 

294,551 

 

 

288,232 

Capitalization:

 

 

 

 

 

  Long-Term Debt

 

305,038 

 

 

303,872 

 

 

 

 

 

 

  Common Stockholder's Equity:

 

 

 

 

 

    Common stock, $25 par value - authorized

 

 

 

 

 

     1,072,471 shares; 434,653 shares outstanding

 

 

 

 

 

     in 2008 and 2007

 

10,866 

 

 

10,866 

    Capital surplus, paid in

 

144,544 

 

 

128,228 

    Retained earnings

 

106,757 

 

 

103,925 

    Accumulated other comprehensive income

 

102 

 

 

231 

  Common Stockholder's Equity

 

262,269 

 

 

243,250 

Total Capitalization

 

567,307 

 

 

547,122 

 

 

 

 

 

 

Commitments and Contingencies (Note 5)

 

 

 

 

 

 

 

 

 

 

 

Total Liabilities and Capitalization

 

$          1,012,584 

 

 

$              991,088 

 

 

   

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 

 




47





WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

 

 

 

 

 

 

 

 

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2008

 

 

2007

 

 

2008

 

 

2007

 

 

(Thousands of Dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

$   104,215 

 

 

$   112,363 

 

 

$   219,974 

 

 

$   241,921 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

  Operation -

 

 

 

 

 

 

 

 

 

 

 

     Fuel, purchased and net interchange power

 

51,355 

 

 

56,736 

 

 

113,494 

 

 

127,907 

     Other

 

22,467 

 

 

25,037 

 

 

41,575 

 

 

49,464 

  Maintenance

 

5,472 

 

 

4,985 

 

 

10,049 

 

 

9,317 

  Depreciation

 

5,251 

 

 

5,238 

 

 

10,444 

 

 

10,486 

  Amortization of regulatory assets, net

 

3,654 

 

 

1,926 

 

 

6,409 

 

 

4,215 

  Amortization of rate reduction bonds

 

3,365 

 

 

3,151 

 

 

6,807 

 

 

6,382 

  Taxes other than income taxes

 

3,008 

 

 

2,976 

 

 

6,374 

 

 

6,401 

        Total operating expenses

 

94,572 

 

 

100,049 

 

 

195,152 

 

 

214,172 

Operating Income

 

9,643 

 

 

12,314 

 

 

24,822 

 

 

27,749 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

 

 

 

 

 

 

  Interest on long-term debt

 

3,263 

 

 

2,656 

 

 

6,686 

 

 

5,305 

  Interest on rate reduction bonds

 

1,312 

 

 

1,490 

 

 

2,660 

 

 

3,011 

  Other interest

 

274 

 

 

963 

 

 

625 

 

 

1,528 

     Interest expense, net

 

4,849 

 

 

5,109 

 

 

9,971 

 

 

9,844 

Other Income, Net

 

477 

 

 

448 

 

 

724 

 

 

936 

Income Before Income Tax Expense

 

5,271 

 

 

7,653 

 

 

15,575 

 

 

18,841 

Income Tax Expense

 

2,022 

 

 

3,063 

 

 

6,006 

 

 

7,334 

Net Income

 

$       3,249 

 

 

$       4,590 

 

 

$       9,569 

 

 

$     11,507 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.



48





WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

 

 

 

 

 

 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

 

(Unaudited)

 

 

 

 

 

 

 

Six Months Ended

 

 

June 30,

 

 

2008

 

 

2007

 

 

(Thousands of Dollars)

 

 

 

 

 

 

Operating Activities:

 

 

 

 

 

Net income

$

9,569 

 

$

11,507 

Adjustments to reconcile to net cash flows

 

 

 

 

 

  provided by/(used in) operating activities:

 

 

 

 

 

Bad debt expense

 

4,022 

 

 

  3,282 

Depreciation

 

10,444 

 

 

10,486 

Deferred income taxes

 

3,546 

 

 

(8,590)

Pension income, net of capitalized portion

 

 (1,885)

 

 

 (1,500)

Amortization of rate reduction bonds

 

6,807 

 

 

6,382 

Amortization of regulatory assets, net

 

6,409 

 

 

4,215 

Regulatory overrecoveries

 

1,755 

 

 

24,642 

Deferred contractual obligations

 

(3,033)

 

 

(4,264)

Other non-cash adjustments

 

 (1,163)

 

 

 (1,507)

Other sources of cash

 

 

 

370 

Other uses of cash

 

(1,267)

 

 

 (398)

Changes in current assets and liabilities:

 

 

 

 

 

Receivables and unbilled revenues, net

 

 (3,432)

 

 

 (13,083)

Materials and supplies

 

 (984)

 

 

50 

Other current assets

 

184 

 

 

 (942)

Accounts payable

 

53 

 

 

 (1,782)

Taxes receivable/accrued

 

 (2,338)

 

 

 (34,746)

Counterparty deposits

 

9,019 

 

 

Other current liabilities

 

173 

 

 

274 

Net cash flows provided by/(used in) operating activities

 

37,879 

 

 

 (5,604)

 

 

 

 

 

 

Investing Activities:

 

 

 

 

 

Investments in property and plant

 

 (27,945)

 

 

 (21,921)

Proceeds from sales of investment securities

 

90,755 

 

 

76,427 

Purchases of investment securities

 

 (91,180)

 

 

 (78,118)

Other investing activities

 

386 

 

 

 (5)

Net cash flows used in investing activities

 

 (27,984)

 

 

 (23,617)

 

 

 

 

 

 

Financing Activities:

 

 

 

 

 

Retirement of rate reduction bonds

 

 (6,855)

 

 

(6,433)

(Decrease)/increase in NU Money Pool borrowings

 

 (11,600)

 

 

37,000 

Capital contributions from NU parent

 

16,281 

 

 

4,800 

Cash dividends on common stock

 

(6,737)

 

 

(6,389)

Net cash flows (used in)/provided by financing activities

 

 (8,911)

 

 

28,978 

Net increase/(decrease) in cash

 

984 

 

 

  (243)

Cash - beginning of period

 

1,110 

 

 

1,336 

Cash - end of period

$

2,094 

 

$

1,093 

 

 

 

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 

 

 

 

 




49




NORTHEAST UTILITIES AND SUBSIDIARIES

Management's Discussion and Analysis of
Financial Condition and Results of Operations


The following discussion and analysis should be read in conjunction with the condensed consolidated financial statements and related notes included in this Quarterly Report on Form 10-Q, Northeast Utilities and subsidiaries combined first quarter 2008 Quarterly Report on Form 10-Q (the First Quarter 2008 Form 10-Q) and the Northeast Utilities and subsidiaries combined 2007 Annual Report on Form 10-K (2007 Form 10-K) as filed with the Securities and Exchange Commission (SEC).  References in this Form 10-Q to "NU" or "the company" are to Northeast Utilities combined with its subsidiaries, and the terms "we," "us" and "our" refer to NU.  All per share amounts are reported on a fully diluted basis.


The only common equity securities that are publicly traded are common shares of NU.  The earnings per share (EPS) of each segment discussed below does not represent a direct legal interest in the assets and liabilities allocated to such segment but rather represents a direct interest in our assets and liabilities as a whole.  EPS by segment is a measure not recognized under accounting principles generally accepted in the United States of America (GAAP) that is calculated by dividing the net income or loss of each segment by the average fully diluted NU common shares outstanding for the period.  We use this measure to provide segmented earnings guidance and believe that this measurement is useful to investors to evaluate the actual financial performance and contribution of our business segments.  This non-GAAP measure should not be considered as an alternative to our consolidated fully diluted EPS determined in accordance with GAAP as an indicator of our operating performance.


The discussion below also references our 2008 earnings and EPS excluding a significant charge associated with the settlement of litigation with Consolidated Edison, Inc. (Con Edison).  We use these non-GAAP measures to more fully explain and compare the 2008 and 2007 results without including the impact of certain non-recurring items.  Due to the nature and significance of the settlement charge, management believes that this non-GAAP presentation is more representative of our performance and provides additional and useful information to investors in analyzing historical and future performance.  These measures should not be considered as alternatives to our reported net income or EPS determined in accordance with GAAP as indicators of our operating performance.


Reconciliations of above non-GAAP measures to respective GAAP measures of consolidated fully diluted EPS and net income are included under "-Financial Condition and Business Analysis-Overview-Consolidated" and "-Financial Condition and Business Analysis-Future Outlook."


FINANCIAL CONDITION AND BUSINESS ANALYSIS


Executive Summary


The following items in this executive summary are explained in more detail in this quarterly report:


Results, Strategy and Outlook:


·

We earned $57.8 million, or $0.37 per share, in the second quarter of 2008, compared with $48.5 million, or $0.31 per share, in the second quarter of 2007.  The results in 2008 included regulated companies net income of $60.8 million, or $0.39 per share, after payment of preferred dividends, NU Enterprises, Inc. (NU Enterprises) net income of $2.2 million, or $0.01 per share, and NU parent and other companies net losses of $5.2 million, or $0.03 per share.  


·

We earned $116.2 million, or $0.75 per share, in the first half of 2008, compared with $123.6 million, or $0.80 per share, in the first half of 2007.  The 2008 results included regulated companies net income of $147.1 million, or $0.94 per share, after payment of preferred dividends, NU Enterprises net income of $4.1 million, or $0.03 per share, and NU parent and other companies net losses of $35 million, or $0.22 per share.  The NU parent loss includes an after-tax charge of $29.8 million, or $0.19 per share, resulting from the settlement of litigation with Con Edison.  Excluding that charge, our earnings in the first half of 2008 were $146 million, or $0.94 per share.


·

Earnings at the distribution segments of The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) (including regulated generation), Western Massachusetts Electric Company (WMECO) and Yankee Gas Services Company (Yankee Gas) totaled $25.6 million in the second quarter of 2008 and $79.4 million in the first half of 2008, compared with $23.4 million in the second quarter of 2007 and $71.6 million in the first half of 2007.  These results reflect the fact that second quarter and first half 2008 electric sales were lower than sales in 2007 on an actual and weather normalized basis.  Firm natural gas sales on an actual basis were also lower for the first half of 2008, but higher for the second quarter of 2008, as



50




compared to sales in the same periods in 2007.  Firm natural gas sales on a weather normalized basis were higher for the second quarter of 2008 and for the first half of 2008 as compared to sales in the same periods in 2007.  Changes in electric sales have a lesser impact on earnings than in prior years due to current rate design, which recovers the majority of revenues through non-usage charges.


·

The transmission segments of CL&P, PSNH and WMECO earned $35.2 million in the second quarter of 2008 and $67.7 million in the first half of 2008, compared with $21.1 million in the second quarter of 2007 and $37 million in the first half of 2007.


·

CL&P continues to work on its three major transmission projects in southwest Connecticut.  The Glenbrook Cables project is on schedule to be completed by the end of 2008, and the Middletown-Norwalk project is ahead of schedule and construction is currently expected to be completed in the first quarter of 2009.  The Long Island Replacement Cable project was energized and placed into service on July 29, 2008.  The Connecticut portion of the cable has been buried, however, the New York portion will be buried this fall in accordance with New York state permits.  For more information on these projects, see "Business Development and Capital Expenditures - Regulated Companies - Transmission Segment" in this Management's Discussion and Analysis.


·

We now project consolidated 2008 earnings of between $1.60 per share and $1.75 per share, including the effect of the settlement with Con Edison, and between $1.80 per share and $1.95 per share excluding it.  This projection represents an increase over prior guidance of $0.15 per share for the low-end of the range and $0.05 per share for the high end of the range.  


Legal, Regulatory and Other Items:


·

On June 11, 2008, the Connecticut Department of Public Utility Control (DPUC) issued a final order pursuant to which Yankee Gas is required to refund to customers approximately $5.8 million in previous recoveries under Yankee Gas’s Purchased Gas Adjustment (PGA) clause.  The $5.8 million pre-tax charge (approximately $3.5 million net of tax) was recorded in the second quarter 2008 earnings of Yankee Gas.  


·

On June 25, 2008, the DPUC issued a final decision approving three proposed peaking generation units totaling 678 MW of summer peaking capacity and rejecting nine others, including both units that had been proposed by CL&P.  In the third quarter of 2008, contracts for differences (CfDs) with the developers of the three approved units were signed or are expected to be signed by CL&P and UI, which were directed by the DPUC to share the net costs and benefits of the contracts on a basis of 80 percent and 20 percent, respectively.  


·

On July 16, 2008, the Massachusetts Department of Public Utilities (DPU) issued a decision requiring all gas and electric utilities to file full decoupling proposals with their next general rate case.  WMECO is currently evaluating the timing of its next rate case.


·

On July 17, 2008, the Federal Energy Regulatory Commission (FERC) granted CL&P’s request for a waiver of the provision of the FERC’s March 24, 2008 order limiting its 100 basis point ROE adder solely to projects "completed and on line" by December 31, 2008 and approved the 100 basis point incentive for CL&P’s entire Middletown-Norwalk transmission project.  The FERC also granted an additional 50 basis point adder for the advanced technology aspects of the 24-mile underground portion of the project, which will be limited to 46 basis points based on the present overall ROE limit established by the FERC in the March 2008 order.  We expect to increase our consolidated annual earnings beginning in 2009 by approximately $1 million once all the advanced technology equipment is in service.


Liquidity:


·

Our cash capital expenditures totaled $625.1 million in the first half of 2008, compared with $491.1 million in the first half of 2007.  The increase in our cash capital expenditures was primarily the result of higher transmission segment capital expenditures, particularly at CL&P.


·

After giving effect to certain significant items impacting operating cash flows period over period, as discussed under "Liquidity - Consolidated" in this Management's Discussion and Analysis, cash flows provided by operations in the first half of 2008 were down slightly from the prior year.  We continue to project that we will generate between $450 million and $500 million of cash flows from operations in 2008 after repayment of rate reduction bonds but before the net effect of the Con Edison settlement payment.


·

In the second quarter of 2008, NU parent, CL&P and PSNH issued a total of $660 million of long-term debt, which was used to repay short-term debt, to fund ongoing capital investment programs and for general working capital purposes.  A portion of the $250 million received by NU parent from its debt issuance was also used to repay a $150 million long-term debt note that



51




matured on June 1, 2008.  As a result of these issuances, we had approximately $768 million of borrowing availability on our $900 million revolving credit lines as of June 30, 2008.


·

On June 30, 2008, CL&P terminated the arrangement under which a financial institution could purchase up to $100 million of CL&P’s accounts receivable and unbilled revenues due to the availability and relative cost of other liquidity sources.  We believe that we have sufficient liquidity without this arrangement.


Overview


Consolidated:  We earned $57.8 million, or $0.37 per share, in the second quarter of 2008 and $116.2 million, or $0.75 per share, in the first half of 2008, compared with $48.5 million, or $0.31 per share, in the second quarter of 2007 and $123.6 million, or $0.80 per share, in the first half of 2007.  Excluding an after-tax charge of $29.8 million, or $0.19 per share, associated with the settlement of litigation with Con Edison, our earnings in the first half of 2008 were $146 million, or $0.94 per share.  A summary of our earnings by segment, which also reconciles consolidated net income and fully diluted EPS to the respective non-GAAP measures of consolidated non-GAAP earnings and EPS, as well as EPS by segment, for the second quarter and first half of 2008 and 2007, is as follows:


 

 

For the Three Months Ended June 30,

 

For the Six Months Ended June 30,

 

 

2008

 

2007

 

2008

 

2007

(Millions of Dollars, except per share amounts)

 

Amount

 

Per Share

 

Amount

 

Per Share

 

Amount

 

Per Share

 

Amount

 

 

Per Share

Net Income (GAAP)

 

$

57.8 

 

$

0.37 

 

$

48.5 

 

$

0.31 

 

$

116.2 

 

$

0.75 

 

$

123.6 

 

$

0.80 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulated companies

 

$

60.8 

 

$

0.39 

 

$

44.5 

 

$

0.29 

 

$

147.1 

 

$

0.94 

 

$

108.6 

 

$

0.70 

NU Enterprises

 

 

2.2 

 

 

0.01 

 

 

2.5 

 

 

0.01 

 

 

4.1 

 

 

0.03 

 

 

7.4 

 

 

0.05 

NU parent and other companies

 

 

(5.2)

 

 

(0.03)

 

 

1.5 

 

 

0.01 

 

 

(5.2)

 

 

(0.03)

 

 

7.6 

 

 

0.05 

Non-GAAP earnings

 

 

57.8 

 

 

0.37 

 

 

48.5 

 

 

0.31 

 

 

146.0 

 

 

0.94 

 

 

123.6 

 

 

0.80 

Con Edison litigation charge

 

 

 

 

 

 

 

 

 

 

(29.8)

 

 

(0.19)

 

 

 

 

Net Income (GAAP)

 

$

57.8 

 

$

0.37 

 

$

48.5 

 

$

0.31 

 

$

116.2 

 

$

0.75 

 

$

123.6 

 

$

0.80 


Regulated Companies:   Our regulated companies, which consist of CL&P, PSNH, WMECO and Yankee Gas, segment their earnings between their electric transmission segment and their electric and gas distribution segments, with PSNH generation included with the electric distribution segment.  A summary of regulated company earnings by segment for the second quarter and first half of 2008 and 2007 is as follows:


 

 

For the Three Months
Ended June 30,

 

For the Six Months
Ended June 30,

(Millions of Dollars)

 

 

2008

 

 

2007

 

 

2008

 

 

2007

CL&P Transmission*

 

$

30.0 

 

$

17.4 

 

$

55.8 

 

$

30.4 

PSNH Transmission

 

 

3.6 

 

 

2.6 

 

 

8.8 

 

 

4.5 

WMECO Transmission

 

 

1.6 

 

 

1.1 

 

 

3.1 

 

 

2.1 

     Total Transmission

 

 

35.2 

 

 

21.1 

 

 

67.7 

 

 

37.0 

CL&P Distribution*

 

 

14.8 

 

 

7.0 

 

 

33.7 

 

 

27.6 

PSNH Distribution and Generation

 

 

10.1 

 

 

12.6 

 

 

21.6 

 

 

20.7 

WMECO Distribution

 

 

1.7 

 

 

3.5 

 

 

6.5 

 

 

9.4 

Yankee Gas

 

 

(1.0)

 

 

0.3 

 

 

17.6 

 

 

13.9 

      Total Distribution and Generation

 

 

25.6 

 

 

23.4 

 

 

79.4 

 

 

71.6 

Net Income - Regulated Companies

 

$

60.8 

 

$

44.5 

 

$

147.1 

 

$

108.6 


*After preferred dividends in all periods.


The higher second quarter and first half 2008 transmission segment earnings reflect a higher level of investment in this segment as we continue to build out our transmission infrastructure to meet the region’s reliability needs.  CL&P’s transmission earnings increased primarily due to CL&P’s significant ongoing investment in projects in southwest Connecticut.  The first half 2008 transmission segment results also included first quarter earnings of approximately $3.5 million associated with an order on rehearing issued by the FERC on March 24, 2008 concerning the ROE allowed to owners of New England electric transmission facilities, including CL&P, PSNH and WMECO.


CL&P’s second quarter 2008 distribution segment earnings were $7.8 million higher than the same period in 2007 primarily due to higher distribution revenues resulting from the distribution rate increase effective February 1, 2008, and a lower effective income tax rate, partially offset by a 5.8 percent reduction in sales and higher operating costs.


For the first six months of 2008, CL&P’s distribution segment earnings were $6.1 million higher than the same period in 2007 primarily due to higher distribution revenues, higher other revenues resulting from financial incentives under the 2005 "Act



52




Concerning Energy Independence" to promote distributed generation and demand side management, and a lower effective income tax rate.  These items were partially offset by a 4 percent reduction in sales and higher operating costs.  For the 12 months ended June 30, 2008, CL&P’s distribution segment Regulatory ROE was 8.2 percent.  We expect CL&P to achieve a distribution Regulatory ROE close to 8 percent in calendar year 2008.


PSNH’s second quarter 2008 distribution and generation segment earnings were $2.5 million lower than the same period in 2007.  PSNH’s distribution and generation segment revenues increased as a result of distribution rate increases on July 1, 2007 and January 1, 2008, and a pre-tax adjustment to its generation segment cost recovery mechanism of $1.9 million, which were offset by a 1 percent decrease in sales and higher operating costs.  The decrease in 2008 earnings was primarily due to the implementation of a retail transmission cost tracking mechanism in the second quarter of 2007 which provided for the recovery of $4.5 million of retail transmission costs that were expensed in 2006.  


PSNH’s distribution and generation segment earnings for the six months ended June 30, 2008 were slightly higher than the same period in 2007 primarily due to higher revenues as a result of distribution rate increases and a pre-tax adjustment to its generation segment cost recovery mechanism of $1.9 million, mostly offset by higher operating costs and the absence of the $4.5 million pre-tax benefit from the implementation of the retail transmission cost tracking mechanism in the second quarter of 2007.  For the 12 months ended June 30, 2008, PSNH’s combined distribution and generation segment Regulatory ROE was 8.8 percent.  We expect PSNH to achieve a combined distribution and generation Regulatory ROE close to 9 percent in calendar year 2008.


WMECO’s second quarter 2008 distribution segment earnings were $1.8 million lower than the same period in 2007, and for the first half of 2008, its distribution segment earnings were $2.9 million lower than the same period in 2007.  The decline in earnings was primarily due to a $1.6 million pre-tax charge related to a DPU ruling on WMECO's 2005 and 2006 transition charge reconciliations, lower sales, and higher operating costs.  For the 12 months ended June 30, 2008, WMECO’s distribution segment Regulatory ROE was 8.2 percent.  We expect WMECO to achieve a distribution Regulatory ROE close to 8 percent in calendar year 2008, which is lower than our previous expectation of between 9 percent and 9.5 percent.  The decrease in the projected Regulatory ROE is primarily due to the DPU ruling on WMECO’s 2005 and 2006 transition charge reconciliations, lower revenues and higher operating costs.


Yankee Gas’s second quarter 2008 earnings were $1.3 million lower than the same period in 2007, primarily due to a DPUC order requiring Yankee Gas to refund $5.8 million of previous gas cost recoveries.  This pre-tax charge was partially offset by higher revenues that resulted from a rate increase that took effect July 1, 2007.  Yankee Gas’s earnings for the first half of 2008 were $3.7 million higher than the same period in 2007, primarily due to higher revenues, partially offset by the refund described above and higher operating costs.  Revenues were also impacted by a 2.6 percent decline in firm natural gas sales due primarily to warmer weather in the first quarter of 2008.  For the 12 months ended June 30, 2008, Yankee Gas’s Regulatory ROE was 9.1 percent.  We expect Yankee Gas to achieve a Regulatory ROE close to 8 percent in calendar year 2008, which is lower than our previous expectation of between 9 percent and 9.5 percent.  The decrease in the projected Regulatory ROE is primarily due to the DPUC's order requiring a refund of previous gas cost recoveries and increases in the cost of fuel inventories.


For the distribution segment of our regulated companies, a summary of changes in CL&P, PSNH and WMECO retail electric kilowatt-hour sales and Yankee Gas firm natural gas sales for the second quarter and first half of 2008 as compared to the same periods in 2007 on an actual and weather normalized basis (using a 30-year average) is as follows:


 

 

For the Three Months Ended June 30, 2008 Compared to 2007

 

 

Electric

 

Firm Natural Gas

 

 

CL&P

 

PSNH

 

WMECO

 

Total

 

Yankee Gas

 

 



Percentage
(Decrease)/
Increase

 

Weather
Normalized
Percentage
(Decrease)/
Increase

 



Percentage
(Decrease)/
Increase

 

Weather
Normalized
Percentage
(Decrease)/
Increase

 


Percentage
Decrease

 

Weather
Normalized
Percentage
Decrease

 


Percentage
(Decrease)/
Increase

 

Weather
Normalized
Percentage
(Decrease)/
Increase

 


Percentage
(Decrease)/
Increase

 

Weather
Normalized
Percentage
Increase

Residential

 

(4.0)%

 

(3.3)%

 

(1.3)%

 

(0.3)%

 

(4.2)%

 

(3.4)%

 

(3.4)%

 

(2.6)%

 

(3.3)%

 

4.4%

Commercial

 

(3.8)%

 

(3.8)%

 

1.7 %

 

2.2 %

 

(0.7)%

 

(0.7)%

 

(2.3)%

 

(2.1)%

 

(2.0)%

 

4.6%

Industrial

 

(17.1)%

 

(17.0)%

 

(6.0)%

 

(5.7)%

 

(8.4)%

 

(8.5)%

 

(12.8)%

 

(12.7)%

 

10.6 %

 

12.1%

Other

 

2.9 %

 

2.9 %

 

0.3 %

 

0.3 %

 

(7.1)%

 

(7.1)%

 

2.1 %

 

2.1 %

 

0.0 %

 

0.0%

Total

 

(5.8)% 

 

(5.5)% 

 

(1.0)% 

 

(0.4)% 

 

(3.8)% 

 

(3.5)% 

 

(4.5)% 

 

(4.1)% 

 

2.4 % 

 

7.4% 




53





 

 

For the Six Months Ended June 30, 2008 Compared to 2007

 

 

Electric

 

Firm Natural Gas

 

 

CL&P

 

PSNH

 

WMECO

 

Total

 

Yankee Gas

 

 



Percentage
Decrease

 

Weather
Normalized
Percentage
Decrease

 



Percentage
(Decrease)/
Increase

 

Weather
Normalized
Percentage
(Decrease)/
Increase

 


Percentage
Decrease

 

Weather
Normalized
Percentage
Decrease

 


Percentage
Decrease

 

Weather
Normalized
Percentage
Decrease

 


Percentage
(Decrease)/
Increase

 

Weather
Normalized
Percentage
(Decrease)/
Increase

Residential

 

(4.4)%

 

(3.3)%

 

(0.9)%

 

(0.3)%

 

(3.1)%

 

(2.1)%

 

(3.5)%

 

(2.6)%

 

(7.1)%

 

(2.2)%

Commercial

 

(1.3)%

 

(1.2)%

 

1.7 %

 

2.0 %

 

(0.5)%

 

(0.4)%

 

(0.6)%

 

(0.4)%

 

(4.1)%

 

0.4 %

Industrial

 

(11.1)%

 

(11.1)%

 

(4.7)%

 

(4.5)%

 

(7.1)%

 

(7.1)%

 

(8.7)%

 

(8.7)%

 

5.2 %

 

6.6 %

Other

 

(4.8)%

 

(4.8)%

 

1.0 %

 

1.0 %

 

(3.3)%

 

(3.3)%

 

(4.3)%

 

(4.3)%

 

0.0 %

 

0.0 %

Total

 

(4.0)% 

 

(3.5)% 

 

(0.5)% 

 

(0.1)% 

 

(2.9)% 

 

(2.5)% 

 

(3.1)% 

 

(2.6)% 

 

(2.6)% 

 

1.2 % 


A summary of our retail electric sales in gigawatt hours for CL&P, PSNH and WMECO and firm natural gas sales in million cubic feet for Yankee Gas for the second quarter and first half of 2008 and 2007 is as follows:  


 

 

For the Three Months Ended June 30,

 

 

Electric

 

Firm Natural Gas

 

 


2008

 

2007

 

Percentage
(Decrease)/
Increase

 

2008

 

2007

 

Percentage
(Decrease)/
Increase

Residential

 

3,126 

 

3,237 

 

(3.4)%

 

2,098 

 

2,169 

 

(3.3)%

Commercial

 

3,640 

 

3,726 

 

(2.3)%

 

2,127 

 

2,170 

 

(2.0)%

Industrial

 

1,291 

 

1,481 

 

(12.8)%

 

2,992 

 

2,706 

 

10.6 %

Other

 

76 

 

74 

 

2.1 %

 

 

 

0.0 %

Total

 

8,133 

 

8,518 

 

(4.5)%

 

7,217 

 

7,045 

 

2.4 %


 

 

For the Six Months Ended June 30,

 

 

Electric

 

Firm Natural Gas

 

 


2008

 

2007

 

Percentage
Decrease

 

2008

 

2007

 

Percentage
(Decrease)/
Increase

Residential

 

7,111 

 

7,372 

 

(3.5)%

 

7,907 

 

8,514 

 

(7.1)%

Commercial

 

7,357 

 

7,397 

 

(0.6)%

 

7,577 

 

7,904 

 

(4.1)%

Industrial

 

2,525 

 

2,767 

 

(8.7)%

 

6,835 

 

6,500 

 

5.2 %

Other

 

167 

 

175 

 

(4.3)%

 

 

 

0.0 %

Total

 

17,160 

 

17,711 

 

(3.1)%

 

22,319 

 

22,918 

 

(2.6)%


Second quarter and first half 2008 actual and weather normalized electric sales were lower than sales in the same periods of 2007.  The 2008 results reflect the fact that our customers are responding to the increasing costs of energy and the economic conditions of our region in different ways including the installation of distributed generation, utilization of conservation and load management programs, and the taking of steps to reduce their usage of electricity and reduce their usage in peak hours.  


Changes in electric sales, however, have less of an impact on the earnings of the electric companies than in prior years because non-distribution revenues, which represent approximately 75 percent of electric company revenues, are tracked and reconciled to actual costs.  Non-distribution revenues include the energy, stranded cost, retail transmission and federally mandated congestion cost (FMCC) charges and other components of rates.  For non-distribution revenues, the only impact to earnings is from the carrying costs on over- or underrecoveries.  Also, more than half of each of the electric company’s distribution revenues is recovered through charges that are not dependent on overall sales volumes, such as the customer charge and demand charge.  


In addition to the manner in which the distribution revenues are recovered from customers, there are other reasons why changes in 2008 sales have less of an impact on our earnings.  For example, some of the decline in 2008 industrial sales was due to qualified distributed generation in Connecticut replacing our distribution.  Under Connecticut statute, CL&P is entitled to recover this lost distribution revenue through its FMCC charge.  Also, some of the decline in 2008 commercial sales was attributable to certain generators who, in previous periods, took station service from CL&P as retail commercial customers but now are served directly by ISO-NE as wholesale customers.  These customers are interconnected to the transmission system and do not contribute to distribution revenues, therefore the loss of load from these customers in 2008 did not impact our earnings.


Overall, the pass-through nature of non-distribution revenues, the rate design of the distribution revenues and the lack of impact from the migration of station service sales combine to lessen the impact on earnings from reduced sales.  


Firm natural gas sales on a weather normalized basis were higher in the second quarter and first half of 2008 when compared to sales in the same periods in 2007, but on an actual basis, sales for the first six months of 2008 were lower than sales in 2007 due to warmer weather in the first quarter of 2008.  The majority of the increase in 2008 sales was in the industrial sector, and approximately half of the growth in industrial sales was due to the addition of customer-owned gas-fired distributed generation.  Similar to our electric distribution companies, Yankee Gas would be entitled to recover over half of its revenues through non-usage charges if the DPUC approves its latest rate design proposal.



54





For the remainder of the year, we expect CL&P and PSNH weather normalized sales to be similar to the weather normalized sales for the first six months of 2008, but we believe weather normalized sales for WMECO could decline slightly.  For Yankee Gas, we expect weather normalized sales to improve slightly.


Consistent with our sales results over the first half of 2008, our uncollectibles expense is also being influenced by the economic conditions of our region.  Our write-offs as a percentage of revenues increased in 2008 for all our distribution companies, especially WMECO.  As a result, our uncollectibles expense in the second quarter of 2008 was greater than expected, and our projected 2008 expense is somewhat higher than previously estimated.  Similar to the changes in our retail sales, changes in our uncollectibles expense have less of an impact on the earnings of our distribution companies for a number of reasons.  For example, a portion of the uncollectible expense for each of the electric distribution companies is allocated to its respective energy supply rate and recovered as a tracked expense.  Additionally, for CL&P and Yankee Gas, write-offs attributable to hardship customers are tracked and fully recovered as authorized by statute.  PSNH and WMECO offer discounts to limited income customers, and these discounts are also recovered.


NU Enterprises:  NU Enterprises, which continues to manage to completion its remaining wholesale marketing contracts and energy services activities, earned $2.2 million in the second quarter of 2008 and $4.1 million in the first half of 2008, compared with $2.5 million in the second quarter of 2007 and $7.4 million in the first half of 2007.  First half 2008 results include an after-tax reduction of earnings of $2.4 million associated with the implementation of SFAS No. 157, net of a $1.3 million benefit from partially reversing the SFAS No. 157 implementation charge as we served rather than exited Select Energy Inc.’s (Select Energy) wholesale marketing contracts in 2008.  NU Enterprises' earnings for the second quarter of 2008 and 2007 included negative mark-to-market impacts of $1.4 million and $2.7 million, respectively, associated with the wholesale marketing contracts.  NU Enterprises' earnings for the first half of 2008 and 2007 included negative mark-to-market impacts of $0.9 million and $1.2 million, respectively, associated with the wholesale marketing contracts.


NU Parent and Other Companies:   NU parent and other companies lost $5.2 million in the second quarter of 2008 and $35 million in the first half of 2008, compared with earnings of $1.5 million in the second quarter of 2007 and $7.6 million in the first half of 2007.  The 2008 first half loss results from the payment by NU parent to Con Edison of $49.5 million in March 2008 as part of a comprehensive settlement of litigation initiated in 2001 over the proposed but unconsummated merger between the two companies.  The decrease in earnings from the second quarter and first half of 2007 was also the result of reduced interest income for NU parent on a significantly lower level of cash in 2008.  NU parent carried a high level of cash in the first quarter of 2007 resulting from the sale of our competitive generation businesses on November 1, 2006.  Most of that cash was either invested in the regulated companies in 2007 to support those companies’ capital programs or used to pay taxes due in March 2007 on the competitive generation business sales.  


Future Outlook


2008 Earnings Projection :  We now project consolidated 2008 earnings of between $1.60 per share and $1.75 per share, including the effect of the settlement with Con Edison, and between $1.80 per share and $1.95 per share excluding it.  A summary of our projected 2008 EPS by segment, which also reconciles consolidated fully diluted EPS to the non-GAAP measures of non-GAAP consolidated EPS and EPS by segment, is as follows:


 

 

 

Previously Reported 2008 EPS Range

 

Revised 2008 EPS Range

(Approximate amounts)

 

 

Low

 

 

High

 

 

Low

 

 

High

Fully Diluted EPS (GAAP)

 

$

1.45 

 

$

1.70 

 

$

1.60 

 

$

1.75 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulated companies:

 

 

 

 

 

 

 

 

 

 

 

 

  Distribution and generation segment

 

$

1.05 

 

$

1.15 

 

$

1.05 

 

$

1.10 

  Transmission segment

 

 

0.75 

 

 

0.85 

 

 

0.85 

 

 

0.90 

Total regulated companies

 

 

1.80 

 

 

2.00 

 

 

1.90 

 

 

2.00 

NU Enterprises

 

 

 

 

-  

 

 

 

 

0.05 

NU parent and other companies (excluding
  Con Edison litigation charge)

 

 


(0.15)

 

 


(0.10)

 

 


(0.10)

 

 


(0.10)

Non-GAAP EPS

 

 

1.65 

 

 

1.90 

 

 

1.80 

 

 

1.95 

Con Edison litigation charge

 

 

(0.19)

 

 

(0.19)

 

 

(0.19)

 

 

(0.19)

Fully Diluted EPS (GAAP)

 

$

1.45 

 

$

1.70 

 

$

1.60 

 

$

1.75 


The 2008 earnings guidance for the regulated companies' transmission segment was raised due primarily to the companies' continued success in managing transmission projects and to the effects of the March 2008 FERC decision involving equity returns allowed on transmission projects.  The distribution and generation segment guidance was narrowed due in part to lower sales in the first half of



55




2008 than previously projected.  Additionally, we now estimate that our competitive businesses could earn better than our previous projection due to better than expected operating results in the first half of 2008.  The loss projection for NU parent and other companies has also been narrowed, as interest costs are now projected to be lower than previously anticipated.  

 

Long-Term Growth Rate: We continue to project that we can achieve an average compounded annual EPS growth rate of between 8 percent and 11 percent over 2007 earnings of $1.59 per share for the period 2008 through 2012.  This EPS growth rate assumes achieved Regulatory ROEs of approximately 12 percent for transmission and between 9 percent to 10 percent for generation and distribution investments.  This will require appropriate regulatory approvals and timely rate treatment associated with our electric transmission and distribution investments and natural gas distribution investments in a challenging environment of high energy prices.  It also assumes we achieve our projected levels of capital expenditures and rate base growth in accordance with our present schedule.


Liquidity


Consolidated:   In the second quarter of 2008, our liquidity position benefited from the issuance of a total of $660 million of long-term debt by NU parent, CL&P and PSNH.  On June 5, 2008, NU parent sold $250 million of senior unsecured notes due June 1, 2013 and carrying a coupon of 5.65 percent.  Most of the proceeds were used to repay a $150 million, 3.3 percent note that matured June 1, 2008.  The balance of NU parent's debt issuance was used to pay down short-term debt, a portion of which was incurred in March 2008 as a result of the $49.5 million litigation settlement payment to Con Edison.


On May 27, 2008, CL&P sold $300 million of first and refunding mortgage bonds due May 1, 2018 and carrying a coupon of 5.65 percent.  Also on May 27, 2008, PSNH sold $110 million of first mortgage bonds carrying a coupon of 6 percent and due May 1, 2018.  Proceeds from the CL&P and PSNH issuances were used to repay short-term debt, to fund each company’s ongoing capital investment programs, and for general working capital purposes.  Along with these three debt issuances, Yankee Gas expects to issue up to $100 million of first mortgage bonds in the second half of 2008 primarily to repay short-term debt incurred in funding its capital investment program.  This planned issuance was approved by the DPUC in July 2008.


We had $12.1 million of cash and cash equivalents on hand at June 30, 2008, compared with $15.1 million at December 31, 2007.  We had operating cash flows of approximately $213 million, after rate reduction bond payments and excluding the settlement payment to Con Edison of $49.5 million, in the first half of 2008, compared with operating cash flows of approximately $253 million, after rate reduction bond payments and excluding tax payments of approximately $400 million related to the 2006 sale of the competitive generation business, in the first half of 2007.  Other drivers resulting in decreased operating cash flows in 2008 from 2007 include a reduction from regulatory refunds and underrecoveries (net of income tax impacts) and a net reduction in other working capital items, offset by a benefit from counterparty deposits.


Excluding the $49.5 million Con Edison settlement payment, net of an expected $19.7 million reduction in income tax payments, we project consolidated operating cash flows of approximately $450 million to $500 million in 2008, after payments to retire our rate reduction bonds of approximately $231 million.  This projection includes a potential net income tax settlement of approximately $70 million in the second half of 2008 and a reduction in income tax payments of $35 million over the remainder of the year related to bonus depreciation.    


A summary of the current credit ratings and outlooks by Moody's Investors Service (Moody's), Standard & Poor's (S&P) and Fitch Ratings (Fitch) for NU parent and WMECO’s senior unsecured debt and CL&P and PSNH's first mortgage bonds is as follows:


 

 

Moody's

 

S&P

 

Fitch

 

 

Current

 

Outlook

 

Current

 

Outlook

 

Current

 

Outlook

NU Parent

 

Baa2

 

Stable

 

BBB- 

 

Stable

 

BBB 

 

Stable

CL&P

 

A3

 

Stable

 

BBB+

 

Stable

 

A-

 

Stable

PSNH

 

Baa1

 

Stable

 

BBB+

 

Stable

 

BBB+

 

Stable

WMECO

 

Baa2

 

Stable

 

BBB  

 

Stable

 

BBB+

 

Stable


On July 29, 2008, Moody's changed the outlook of Yankee Gas to stable from negative and affirmed the company's Baa2 corporate credit rating.  


If NU parent’s senior unsecured debt ratings were to be reduced to a sub-investment grade level by either Moody's or S&P, a number of Select Energy's supply contracts would require Select Energy to post additional collateral in the form of cash or letters of credit (LOCs).  Select Energy would, under its remaining contracts, be required to provide collateral or LOCs in the amount of $21.2 million to various unaffiliated counterparties and collateral or LOCs in the amount of $12 million to several independent system operators, in each case at June 30, 2008.  If such a downgrade were to occur, NU parent would be able to provide that collateral.


NU parent paid common dividends of $62.6 million in the first half of 2008, compared with $58.5 million in the first half of 2007.  The increase reflects a 6.7 percent increase in NU parent's common dividend that took effect in the third quarter of 2007.  On May 12,



56




2008, our Board of Trustees approved a quarterly dividend of $0.2125 per share, a 6.25 percent increase over the previous dividend rate, payable on September 30, 2008 to shareholders of record as of September 1, 2008.  


We expect to continue our current policy of dividend increases, subject to the approval of our Board of Trustees and to our future earnings and cash requirements.  In general, the regulated companies pay approximately 60 percent of their cash earnings to NU parent in the form of common dividends.  In the first half of 2008, CL&P, PSNH, WMECO and Yankee Gas paid $53.2 million, $18.2 million, $6.7 million, and $19 million, respectively, in common dividends to NU parent.  In the first half of 2008, NU parent contributed $57.1 million of equity to CL&P, $35.5 million to PSNH, $16.3 million to WMECO, and $20.8 million to Yankee Gas.  


NU parent's ability to pay dividends is not regulated under the Federal Power Act, but may be affected by certain state statutes, the leverage restrictions in its revolving credit agreement and the ability of its subsidiaries to pay dividends.  Unless a higher amount is approved by the FERC, the Federal Power Act limits the payment of dividends by CL&P, PSNH and WMECO to their respective retained earnings balances, and PSNH is required to reserve an additional amount under its FERC hydroelectric license conditions.  In addition, certain state statutes may impose additional limitations on the regulated companies.  CL&P, PSNH, WMECO and Yankee Gas also are parties to a revolving credit agreement that imposes leverage restrictions.


Cash capital expenditures included on the accompanying condensed consolidated statements of cash flows and described in the liquidity section of this Management's Discussion and Analysis do not include amounts incurred on capital projects but not yet paid, cost of removal, the allowance for funds used during construction (AFUDC) related to equity funds, and the capitalized portion of pension expense or income.  Our cash capital expenditures totaled $625.1 million in the first half of 2008, compared with $491.1 million in the first half of 2007.  Our first half 2008 cash capital expenditures included $442 million by CL&P, $119.2 million by PSNH, $27.9 million by WMECO, $23.4 million by Yankee Gas and $12.6 million by other NU subsidiaries.  The increase in our cash capital expenditures was primarily the result of higher transmission segment capital expenditures, particularly at CL&P.  


NU Parent:   NU parent maintains a credit line of $500 million that expires on November 6, 2010.  At June 30, 2008, NU parent had $20 million of LOCs issued for the benefit of certain subsidiaries and $87 million of borrowings outstanding under that facility.  


Regulated Companies:  The regulated companies maintain a joint $400 million credit facility that expires on November 6, 2010.  There were $45 million of long-term borrowings outstanding under that facility at June 30, 2008.


In addition to this revolving credit facility, CL&P had an arrangement with CL&P Receivables Corporation (CRC), a consolidated wholly-owned subsidiary of CL&P, and a financial institution under which the financial institution could purchase up to $100 million of CL&P's accounts receivable and unbilled revenues from CRC.  On June 30, 2008, there were no receivables sold under that facility and CL&P chose to terminate the Receivables Purchase and Sale Agreement due to the availability and relative cost of other liquidity sources.  At this time, we have no further plans to securitize the accounts receivable and unbilled revenues of our regulated companies and will utilize availability under our credit facilities and other financing vehicles, as necessary, to fund the daily operating activities and capital programs of these companies.  


Borrowings under NU’s credit facilities declined in the first half of 2008 as a result of the $660 million of long-term debt issuances noted above.


Impact of Credit Markets:   Certain of CL&P's and PSNH's Pollution Control Revenue Bonds (PCRBs) carry bond insurance intended to enhance credit ratings.  Certain bond insurers, including those insuring our PCRBs, have experienced increased pressure on ratings, with some ratings being reduced, and are on negative watch by the credit rating agencies.  We do not expect the financial condition of our bond insurers to have a material impact on CL&P or PSNH, although concerns regarding the bond insurers' credit strength could increase interest expense associated with $151 million of PCRBs that we may remarket in 2008.  PSNH has $89 million of insured PCRBs that have a variable rate that continues to be set in a 35-day auction.  CL&P has $62 million of insured PCRBs with a fixed rate for a five-year period that expires October 1, 2008.  Prior to that date, we will evaluate whether to change the interest rate mode on these bonds for future periods.   


NU Enterprises:  Most of the working capital and LOCs required by NU Enterprises are currently used to support Select Energy's remaining wholesale contracts.  NU Enterprises' liquidity requirements are minimal.


Business Development and Capital Expenditures


Consolidated:   Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portion of pension expense or income, totaled $658.4 million in the first half of 2008, compared with $531.3 million in the first half of 2007.  Capital expenditures for the regulated companies are expected to total $1.3 billion in 2008, which includes $22 million related to our corporate service company and other affiliated companies that support the regulated companies.  We expect to update our capital expenditure projections for 2009 through 2013 in November 2008.  



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Regulated Companies:


Transmission Segment:   Transmission segment capital expenditures increased by $129 million in the first half of 2008 as compared with 2007 primarily due to expenditures at CL&P, which continues its significant enhancement of its transmission system in southwest Connecticut.  We continue to project total capital expenditures for this segment in 2008 of approximately $700 million. However, due to changes in the timing of certain major transmission projects described below, we now expect to incur total transmission segment capital expenditures of approximately $350 million in 2009 instead of the previous projection of $506 million.  At this time, we continue to project total transmission segment capital expenditures of $3 billion from 2008 through 2012.

 

A summary of transmission segment capital expenditures by company in the first half of 2008 and 2007 is as follows (millions of dollars):


 

 

 

For the Six Months Ended June 30,

 

 

 

2008

 

 

2007

CL&P

 

$

368.7 

 

$

267.4 

PSNH

 

 

41.0 

 

 

22.2 

WMECO

 

 

15.6 

 

 

7.1 

HWP

 

 

1.0 

 

 

0.6 

Totals

 

$

426.3 

 

$

297.3 


CL&P has three major transmission projects currently under construction in southwest Connecticut.  They are:


·

 A 69-mile, 345 kilovolt (KV)/115 KV transmission project from Middletown to Norwalk, Connecticut (Middletown-Norwalk).  CL&P's portion of this project was estimated to cost approximately $1.05 billion.  Originally due to be in service by the end of 2009, construction is currently expected to be complete by the first quarter of 2009.  We expect the 45-mile overhead section of the project to be completed and in service by the end of 2008 and the 24-mile underground section to be substantially complete by the end of 2008 and in service in the first quarter of 2009.  We now expect the project to be completed at a total cost of approximately $1 billion, approximately $50 million below our earlier estimate.  As of July 31, 2008, CL&P's portion of this project was 95 percent complete.  As of June 30, 2008, CL&P had capitalized $817 million associated with this project and placed $274 million into service.

 

·

A two-cable, nine-mile, 115 KV underground transmission project between Norwalk and Stamford, Connecticut (Glenbrook Cables), construction of which began in October 2006.  This project is estimated to cost approximately $223 million and is scheduled to be completed by the end of 2008.  As of July 31, 2008, this project was 93 percent complete.  As of June 30, 2008, CL&P had capitalized $206 million associated with this project and placed $26 million into service.


·

The replacement of the 138 KV, 11-mile undersea electric transmission cable between Norwalk, Connecticut and Northport-Long Island, New York (Long Island Replacement Cable).  CL&P and the Long Island Power Authority (LIPA) each own approximately 50 percent of the line.  CL&P's portion of the project is estimated to cost $72 million.  On July 18, 2008, the New York Public Service Commission approved LIPA's request to energize the Long Island Replacement Cable.  The project was placed into service on July 29, 2008, ahead of the previously anticipated in-service date of October 2008.  The Connecticut portion of the cable has been buried, however, the New York portion will be buried this fall in accordance with New York state permits.  As of June 30, 2008, CL&P had capitalized $67 million associated with this project and placed $4 million into service.


In addition to our current transmission construction in southwest Connecticut, we continue to work with the New England Independent System Operator (ISO-NE) to refine the design for our next series of major transmission projects, the New England East-West Solutions (NEEWS).  That series of projects involves our construction of new overhead 345 KV lines in Massachusetts and Connecticut as well as associated substation work and 115 KV rebuilds.  One of the projects will connect to a new transmission line that National Grid plans to build in Rhode Island.  On May 19, 2008, National Grid and NU presented the ISO-NE Planning Advisory Committee with recommended options for building the NEEWS projects, with formal approval expected by the end of this year.  We estimate that these recommended options will involve approximately $1.49 billion of capital spending by CL&P and WMECO through 2013.  


The first of these, the Greater Springfield Reliability Project, is the largest and most complicated project within NEEWS.  In May 2008, we modified that project by incorporating key elements of our previously planned 115 KV Springfield Underground Cables Project.  The revised Greater Springfield Reliability Project is expected to cost approximately $714 million if built according to our preferred route and configuration.  Municipal consultations began in late June 2008, and we expect CL&P and WMECO to file siting applications with Connecticut and Massachusetts regulators in September 2008.  If approved as expected in 2010, we expect to commence construction in late 2010 and place the project in service by mid-2013.



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Our second major project of NEEWS is the Interstate Reliability Project, which is being designed and built in coordination with National Grid.  NU's share of this project includes a 40-mile 345 KV line from Lebanon, Connecticut to the Connecticut-Rhode Island border where it would connect with enhancements National Grid is designing.  We expect NU's share of this project to cost approximately $250 million, and CL&P plans to file siting applications with Connecticut by the end of 2008 with construction beginning in 2010.  We expect the project to be placed in service as early as late 2012.


The third part of NEEWS is the Central Connecticut Reliability Project, which involves construction of a new line from Bloomfield, Connecticut to Watertown, Connecticut.  This line would provide us with another 345 KV connection to move power into southwest Connecticut, where approximately half of the state’s electricity is consumed.  The timing of this project would be six to twelve months behind the other two projects, and CL&P expects to initiate the siting process in mid-2009 with construction beginning in 2011.  The project is expected to be placed in service in 2013 with a cost of approximately $315 million.  


Included as part of NEEWS are approximately $210 million of reliability related expenditures, many of which may be incurred in advance of the three major projects.  CL&P and WMECO expect to begin filing siting applications related to some of these expenditures later in 2008.  


During the siting approval process, state regulators may require changes in configuration to address local concerns which could increase construction costs.  Our current design for NEEWS does not contemplate any underground 345 KV lines.  Building 345 KV lines underground would increase total costs, and our estimate could be increased during the siting approval process.  


Distribution and Generation Segment:  We now project a total of approximately $541 million of distribution and generation segment capital expenditures for 2008.  A summary of these estimated capital expenditures for the regulated companies’ distribution and generation segments by company for 2008 is as follows (millions of dollars):


CL&P

 

$

299 

PSNH

 

 

167 

WMECO

 

 

35 

Yankee Gas

 

 

40 

Totals

 

$

541 


On February 15, 2008, Yankee Gas and NRG Energy, Inc. entered into a settlement agreement, which among other things, enabled the recovery of approximately $17.5 million of capital costs and expenses incurred by Yankee Gas related to an NRG subsidiary's generating plant construction project that has ceased.  The previously reported Yankee Gas capital expenditures projection for 2008 decreased from $56 million to approximately $40 million primarily as a result of the accounting adjustment recorded in the first half of 2008 related to the settlement agreement.


A summary of distribution and generation segment capital expenditures by company in the first half of 2008 and 2007 is as follows (millions of dollars):


 

 

 

For the Six Months Ended June 30,

 

 

 

2008

 

 

2007

CL&P

 

$

131.6 

 

$

128.0 

PSNH

 

 

69.4 

 

 

56.3 

WMECO

 

 

15.9 

 

 

16.4 

Yankee Gas

 

 

6.2 

 

 

29.1 

Other

 

 

0.3 

 

 

0.1 

Totals

 

$

223.4 

 

$

229.9 


The first half of 2008 capital expenditures at Yankee Gas were reduced by the $17.5 million accounting adjustment described above, while the first half of 2007 capital expenditures included $9.3 million spent on its $108 million liquefied natural gas (LNG) storage and production facility in Waterbury, Connecticut, which was placed in service in July 2007.  


As mandated by New Hampshire statute,  PSNH plans to install a wet scrubber at its coal-fired, two-unit base load Merrimack plant in Bow, New Hampshire (Clean Air Project).  PSNH now estimates that the Clean Air Project will cost approximately $457 million, compared with its initial estimate of $250 million, which will be recovered through PSNH generation rates under the statute.  This revised estimate includes significant increases in the prices for materials, construction services and engineering services required to design and build the scrubber and associated plant.  The Clean Air Project is expected to reduce the two units’ mercury emissions by approximately 85 percent and sulfur dioxide emissions by more than 90 percent, as well as allow PSNH to avoid the purchase of 30,000 sulfur dioxide credits required to be purchased annually.  PSNH expects to start construction on this project in 2009, and under



59




New Hampshire statute, the scrubber must be operational by July 2013.  The first half of 2008 capital expenditures at PSNH include $5.8 million in costs related to this project.  


Strategic Initiatives:   We are evaluating certain development projects that would benefit our customers, such as new regulated generating facilities, investments in wide-spread advanced metering infrastructure (AMI) systems, and transmission projects to better interconnect new renewable generation in northern New England and Canada with southern New England, as well as interconnections within New Hampshire.  The estimated capital expenditures discussed above do not include expenditures related to any of these strategic initiatives.  


Among the projects we are evaluating is construction of new transmission upgrades in northern New Hampshire to support the addition of 400 MW of new renewable generation (including potential wind and biomass generation), along with other upgrades to the New England transmission system.  As our next step in the process of identifying potential solutions to the region’s energy and environmental needs, on March 31, 2008, we filed a formal request with ISO-NE to analyze potential increases in the North-South high voltage power transfer capacity from New Hampshire into Massachusetts to deliver additional power from renewable and low-carbon emitting resources in northern New England and Canada to southern New England.  We requested that ISO-NE analyze the best methods of increasing that capability by 1,500 MW to 2,500 MW.  We expect the economic study of some of the above initiatives by ISO-NE to be completed in 2009.


Transmission Rate Matters and FERC Regulatory Issues


CL&P, PSNH and WMECO and most other New England utilities, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the market rules by which these parties participate in the wholesale markets and acquire transmission services.  Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent from all market participants, has served as the Regional Transmission Organization (RTO) for New England since February 1, 2005.  ISO-NE works to ensure the reliability of the New England transmission system, administers the independent system operator tariff (ISO Tariff), subject to FERC approval, oversees the efficient and competitive functioning of the regional wholesale power market and determines which portion of the costs of our major transmission facilities are regionalized throughout New England.


Transmission - Wholesale Rates:   Wholesale transmission revenues are based on formula rates that are approved by the FERC.  Most of our wholesale transmission revenues are collected under the ISO-NE FERC Electric Tariff No. 3, Transmission, Markets and Services Tariff (Tariff No. 3).  Tariff No. 3 includes RNS and LNS rate schedules to recover fees for transmission and other services.  The RNS rate, administered by ISO-NE and billed to all New England transmission users, is reset on June 1 st of each year and recovers the revenue requirements associated with transmission facilities that benefit the New England region.  The LNS rate, which we administer, is reset on January 1 st and June 1 st of each year and recovers the revenue requirements for local transmission facilities and other transmission costs not recovered under the RNS rate, including 50 percent of the CWIP that is included in rate base on the remaining three southwest Connecticut projects (Middletown-Norwalk, Glenbrook Cables and Long Island Replacement Cable).  The LNS rate calculation recovers total transmission revenue requirements net of revenues received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that we recover all regional and local revenue requirements as prescribed in Tariff No. 3.  Both the RNS and LNS rates provide for annual true-ups to actual costs.  The financial impacts of differences between actual and projected costs are deferred for future recovery from or refund to customers.  In the second quarter of 2008, under the terms of Tariff No. 3, NU recovered $23 million of the 2007 underrecovery and deferred an underrecovery of $21 million for differences in the second quarter of 2008.  As of June 30, 2008, the LNS rates were in a total underrecovery position of approximately $34 million, which will fluctuate period to period.  On June 1, 2008, the RNS rate and LNS rate were increased to reflect true-ups for historical costs and to reflect forecasted capital expenditures.  We believe that these rates will provide us with timely recovery of transmission costs, including costs of our major transmission projects.


FERC ROE Decision:  As a result of an order issued by the FERC on October 31, 2006 relating to incentives on new transmission facilities in New England (Initial ROE Order), we recorded an estimated regulatory liability for refunds in 2006.  In 2007, we completed the customer refunds that were calculated in accordance with the compliance filing required by the Initial ROE Order, and refunded amounts to regional, local and localized transmission customers.


On March 24, 2008, the FERC issued an order on rehearing of its Initial ROE Order.  In the rehearing order, the FERC, among other things, increased the base ROE on transmission projects for the transmission owners from the 10.2 percent allowed in the Initial ROE Order to 10.4 percent effective February 1, 2005 and reaffirmed its Initial ROE Order increasing the ROE by 74 basis points for the period beginning November 1, 2006 in recognition of higher bond yields.  The rehearing order also modified the FERC's Initial ROE Order provision allowing 100 additional basis points for new transmission projects that are built as part of the ISO-NE RSP by limiting the 100 basis points adder solely to projects that are "completed and on line" by December 31, 2008.  In order to receive incentives for projects completed after December 31, 2008, the rehearing order requires transmission owners to file with the FERC project-specific requests that meet the nexus requirements under FERC guidelines.  In addition, while not an issue in this rehearing,



60




the provision of the Initial ROE Order increasing the ROE by 50 additional basis points for New England transmission owners joining an RTO and giving the RTO operational control of the transmission owner’s transmission facilities was left unchanged.  In the first quarter of 2008, we recognized $3.5 million in transmission segment earnings related to this order, of which approximately $2.9 million related to the February 1, 2005 through December 31, 2007 time period.  This order has been appealed to the D.C. Circuit Court of Appeals by various state regulators.  


On June 12, 2008, the New England Conference of Public Utility Commissioners (NECPUC) filed a complaint at the FERC against all of the New England Transmission Owners, including us, seeking to limit the application of the 100 basis point ROE adder to the original transmission project cost estimates in the 2004 ISO-NE Regional Transmission Expansion Planning process.  There is no specific deadline for the FERC to act on a complaint, but responses from all of the New England Transmission Owners have been filed at the FERC.


On May 16, 2008, we filed an application on behalf of CL&P with the FERC to receive return on equity incentives for CL&P’s Middletown-Norwalk project.  The 45-mile 345 KV overhead sections are expected to be in service by the end of 2008 while the 24-mile 345 KV underground sections are expected to be in service in the first quarter of 2009.  On July 17, 2008, the FERC granted a waiver of the December 31, 2008 "completed and on line" date for a 100 basis point ROE adder and approved the 100 basis point incentive for the entire Middletown-Norwalk project.  The FERC also granted an additional 50 basis point adder for the advanced technology aspects of the 24-mile underground portion of the project.  The 50 basis point adder will be limited to 46 basis points based on the present overall ROE limit established by the FERC, resulting in a total ROE for the underground portion of the Middletown-Norwalk project of 13.1 percent.  The cost of the underground portion is estimated to be slightly less than half of CL&P's overall $1.05 billion cost.  Once all advanced technology equipment is in service, the technology adder will increase our consolidated annual earnings beginning in 2009 by approximately $1 million.  Parties have 30 days from the date of this order to seek a rehearing with the FERC.


We also expect to file with the FERC for incentives on each of our other major transmission projects that are completed after December 31, 2008, including our full investment in the NEEWS projects.  Assuming these projects receive the incentives, we expect the projected overall blended ROE in our transmission segment to increase to approximately 12 percent in 2008 and 2009, rising to approximately 12.1 percent in 2010 through 2013.  


Legislative Matters


Environmental Legislation:   RGGI is a voluntary effort by certain northeastern states, including Connecticut, New Hampshire and Massachusetts, to develop a regional program for stabilizing and reducing CO 2 emissions from fossil fuel-fired electric generators.  The initiative proposes to stabilize CO 2 emissions at current levels and requires a 10 percent reduction by 2018 from the initial 2009 permitted levels.  Each signatory state committed to propose for approval the legislative and regulatory mechanisms necessary to implement the program.  The first regional auction of RGGI credits is scheduled for September 2008, though some states may not be ready to participate in this auction.


Connecticut – Connecticut adopted regulations in July 2008 which establish a clearing price threshold of $5 per ton, above which all auction proceeds are rebated to customers.  Connecticut has been allocated approximately 11 million annual credits under the RGGI program.  For revenues up to the clearing price threshold, 69.5 percent will be directed to the conservation and load management programs managed by the state’s utilities in conjunction with the Energy Conservation Management Board.  CL&P’s share of the RGGI funds will be 75 percent of the directed funds.


New Hampshire – Legislation signed by New Hampshire Governor Lynch in June 2008 provides up to a 2.5 million banked-allowance allocation per year for fossil fueled generating plants owned and operated by PSNH during the first three-year compliance period.  PSNH anticipates that this allocation will make up approximately one-half of the credits necessary for its generating plants to comply with RGGI.  PSNH will purchase the additional required credits from quarterly RGGI auctions.  New Hampshire has been allocated approximately 9 million annual credits under the RGGI program.  Additionally, the law sets a clearing price threshold of $6 per ton in 2009, above which all auction proceeds will be rebated to customers.  The law requires that proceeds below the threshold are to be used for demand response and energy efficiency programs.


Massachusetts – Legislation signed by Massachusetts Governor Patrick in July 2008 did not set a clearing price threshold on auction levels.  This act requires that 80 percent of RGGI auction proceeds be allocated to utility energy efficiency and demand response programs.  Allocation and distribution of these funds will be decided by a newly created Energy Efficiency Council.  Utilities are required to file a 3-year energy efficiency plan by April 30, 2009.  Massachusetts has been allocated approximately 26 million annual credits under the RGGI program.




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New Hampshire:   


2008 Legislation:   In July 2008, New Hampshire Governor Lynch signed into law a bill establishing a transmission commission responsible for developing a proposal to expand the electric transmission system in northern New Hampshire to encourage the development of new renewable generation sources.  The transmission commission must finalize its proposal by December 1, 2008.  In 2007, the New Hampshire Public Utilities Commission (NHPUC) had forwarded to the legislature a study that indicated that it would cost approximately $200 million to upgrade northern New Hampshire transmission capacity to support the addition of 300 MW of wind generation and 100 MW of biomass generation.  PSNH is currently evaluating building new transmission upgrades in northern New Hampshire to support the addition of 400 MW of renewable generation in the area.


On July 11, 2008, New Hampshire Governor Lynch signed into law a bill authorizing rate recovery by electric public utilities of investments made in distributed energy resources, such as renewable energy generation.  The total investment is limited to 6 percent of a distribution utility’s peak load.  We have not yet included any investment opportunities for PSNH in our capital expenditure plans.  


Massachusetts:  


2008 Legislation:   As described above, on July 2, 2008, Massachusetts Governor Patrick signed into law a comprehensive energy law called "The Green Communities Act of 2007."  Aimed at increasing energy efficiency (EE) and the use of renewable resources in the state, the Act contains many provisions important to the state’s utilities.  Among other things, the Act:


·

Adopts RGGI for MA and requires that 80 percent of RGGI auction proceeds be earmarked for EE and demand response (DR);

·

Removes the cap on utility expenditures for EE and DR.  Requires utilities to file three-year EE and DR plans with a newly created Energy Efficiency Council;

·

Requires utilities to sign long-term contracts for renewable resources;

·

Allows utilities to own and operate up to 50 MW of solar generation;

·

Requires utilities to file a plan with the DPU for a smart grid pilot; and

·

Increases penalties for failure to meet service quality standards from 2 percent of transmission and distribution revenues to 2.5 percent.


By April 30, 2009, WMECO will prepare a three-year EE and DR investment plan related to the cost of EE and DR programs established by the Act for review by a new Energy Efficiency Council and, ultimately, the DPU.  We have not yet included any investment opportunities for WMECO in our capital expenditure plan.


Regulatory Developments and Rate Matters


Regulated Electric Distribution Companies:  We are currently evaluating the rate case strategy of our electric distribution companies.  Based on each company’s earnings, cost trends and sales trends in 2008, as well as the rate decoupling decision in Massachusetts described below, it is probable that CL&P, PSNH and WMECO will file distribution rate cases in 2009.  


Regulated Companies’ Transmission Revenues - Retail Rates:  A significant portion of our transmission segment revenue comes from ISO-NE charges to the distribution segments of CL&P, PSNH and WMECO, each of which recovers these costs through rates charged to their retail customers.  Each of these companies has a retail transmission cost tracking mechanism as part of their rates, which allows them to charge their retail customers for transmission costs on a timely basis.


Connecticut - CL&P:


Peaking Generation Filing:   In 2007, Connecticut Governor Rell signed into law "An Act Concerning Electricity and Energy Efficiency" (Energy Efficiency Act).  On March 3, 2008, as required by the DPUC under the Energy Efficiency Act, CL&P filed a proposal with the DPUC to build a total of 265 MW of peaking generation.  On June 25, 2008, the DPUC issued a final decision approving three proposed units totaling 678 MW of summer peaking capacity and rejecting nine others, including the two units proposed by CL&P.  CfDs with the developers of the three approved units were signed or are expected to be signed by CL&P and UI in the third quarter of 2008.  As directed by the DPUC, CL&P and UI have entered into a sharing agreement relating to the three CfDs, whereby CL&P is responsible for 80 percent and UI for 20 percent of the net costs or benefits of the contracts.  CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P customers.  


Renewable Energy Contracts:   In May 2008, pursuant to Connecticut's "Act Concerning Energy Independence," (Energy Independence Act), CL&P signed five contracts and UI signed one contract to purchase energy, capacity and renewable energy credits from planned renewable energy plants, including biomass and fuel cell projects approved by the DPUC in January 2008.  



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Purchases under the contracts are scheduled to begin in 2008 through 2011 and range from periods of 15 to 20 years.  As directed by the DPUC, CL&P and UI have also signed a sharing agreement under which they will share the costs and benefits of these contracts, with 80 percent to CL&P and 20 percent to UI.  CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers.  A third round of projects for an additional 26 MW of renewable energy generation is being reviewed by the DPUC for selection in January 2009.


FMCC Filing:  On February 5, 2008, CL&P filed with the DPUC its semi-annual reconciliation to document actual FMCC charges (including Energy Independence Act charges), GSC revenues and expenses and Energy Adjustment Clause (EAC) charges for the period July 1, 2007 through December 31, 2007.  This filing also contained CL&P's revenue and cost information for the period January 1, 2007 through June 30, 2007, for which the DPUC previously approved all costs as filed in its final decision issued January 23, 2008.  This filing identified overrecoveries totaling approximately $105 million for the full year 2007, of which approximately $88 million was reflected in the annual CL&P rate change effective January 1, 2008, and an additional approximately $1 million was reflected in CL&P's Last Resort Service (LRS) rate change effective April 1, 2008.  Therefore, there is a net remaining overrecovery of approximately $16 million from 2007 which, effective July 1, 2008, is being refunded to customers over a six-month period.  A decision on CL&P's semi-annual reconciliation filing is expected to be issued in August 2008.


Standard Service and Last Resort Service Rates:  CL&P's residential and small commercial customers who do not choose competitive suppliers are served under Standard Service (SS) rates, and large commercial and industrial customers who do not choose competitive suppliers are served under LRS  rates.  Effective July 1, 2008, the DPUC approved an increase to CL&P's total average SS and LRS rates of approximately 4.9 percent and 33.2 percent, respectively.  The new LRS rate will remain in effect until September 30, 2008, while the new SS rate will remain in effect until December 31, 2008.  The energy supply portion of the total average SS and LRS rates increased from 11.762 cents per KWH to 11.852 cents per KWH and from 10.466 cents per KWH to 14.559 cents per KWH, respectively.  CL&P is fully and timely recovering the costs of its SS and LRS services.  


Transmission Adjustment Clause: On June 16, 2008, CL&P filed a transmission adjustment clause (TAC) with the DPUC requesting an increase in its retail transmission rate effective July 1, 2008 to collect $67.9 million of additional revenues over the second half of the year.  The increase in the TAC was attributable to the ongoing investment in regional transmission reliability projects.  The DPUC approved CL&P's filing on June 25, 2008.


Customer Service Docket:  On June 19, 2008, the DPUC issued a draft order in a docket investigating CL&P billing errors involving approximately 2,000 customers on time of use rates.  The draft decision found that CL&P had appropriately believed that the correct software changes would be made in time to incorporate new rate structures and rates effective January 1, 2008, but that its actions and communications both internally and externally after it found that the bills were not being accurately calculated were imprudent.  The draft order determined that CL&P was liable for costs associated with the billing errors, which have been expensed as incurred.  A final decision by the DPUC is due in August 2008.  


Connecticut - Yankee Gas:


Purchased Gas Adjustment: In 2005 and 2006, the DPUC issued decisions regarding Yankee Gas’s PGA clause charges and required an audit of previously recovered PGA revenues of approximately $11 million associated with unbilled sales and revenue adjustments for the period of September 1, 2003 through August 31, 2005.  On June 11, 2008, the DPUC issued a final order requiring Yankee Gas to refund approximately $5.8 million in previous recoveries to its customers.  The $5.8 million pre-tax charge (approximately $3.5 million net of tax) was recorded in the second quarter 2008 earnings of Yankee Gas.  


New Hampshire:   


Delivery Service Rates:   On July 1, 2008, PSNH’s distribution rates decreased by approximately $0.4 million annually.  This amount consisted of a $3.4 million rate reduction related to the full recovery of a rate differential recoupment and an annual increase of $3 million for additional funding of the major storm reserve for a two-year period.


The rate differential recoupment was effected pursuant to the NHPUC May 2007 approval of PSNH’s distribution and transmission rate case settlement agreement between PSNH, the NHPUC staff and the New Hampshire Office of Consumer Advocate.  It represents the difference between temporary distribution rates previously allowed and permanent distribution rates ultimately approved by the NHPUC and implemented effective July 1, 2007.


The $3 million additional funding of the major storm reserve was effected pursuant to a rate order issued June 27, 2008 in which the NHPUC accepted PSNH's proposal to increase its distribution rates by approximately $3 million for a two-year period effective July 1, 2008 to eliminate the current negative balance in the major storm reserve and restore the intended reserve level of $1 million.  As part of its review of the PSNH proposal, the NHPUC began an audit of all major storm costs accrued to the major storm reserve



63




and the order states that any adjustments resulting from the major storm reserve audit will be dealt with through future proceedings or as adjustments to the existing major storm reserve balance.  


ES and SCRC Rates:   On June 27, 2008, the NHPUC issued orders increasing the default energy service (ES) rate from 8.82 cents per KWH to 9.57 cents per KWH and lowering the stranded cost recovery charge (SCRC) rate from 0.72 cents per KWH to 0.65 cents per KWH effective on July 1, 2008.  The increase in the ES rate is attributable to an increase in overall energy market prices which results in higher fuel and purchased power costs for 2008, as compared to 2007.  The decrease in the SCRC rate is primarily a result of lower over-market Independent Power Producer (IPP) related costs.


TCAM Reconciliation and Rates:  On May 13, 2008, PSNH filed a  July 1, 2007 through June 30, 2008 transmission cost adjustment mechanism (TCAM) reconciliation and a projected TCAM rate to be billed effective July 1, 2008 related to July 1, 2008 through June 30, 2009 TCAM cost estimates.  Under the terms of an NHPUC rate order issued on June 27, 2008, PSNH’s TCAM rate was increased from 0.752 cents per KWH to 0.935 cents per KWH, effective July 1, 2008.


Renewable Portfolio Standards: On May 11, 2007, New Hampshire Governor Lynch signed into law the "Renewable Energy Act," establishing renewable portfolio standards (RPS) that requires annual increases in the percentage of electricity with direct ties to renewable sources sold to New Hampshire retail customers.  The renewable sourcing requirements begin in 2008 and increase each year to reach 23.8 percent by 2025.


PSNH plans to meet these standards, in part, through the purchase of renewable energy certificates (RECs) from a qualified renewable energy resource.  For each MWH of energy produced from a qualifying renewable resource, the producer will receive one REC. Energy suppliers, like PSNH, will purchase these RECs from the producers and will use them to satisfy the RPS requirements.  To the extent that PSNH is unable to purchase sufficient RECs, it will be required to make up the difference between the RECs purchased and its total obligation by making an alternative compliance payment (ACP) for each REC requirement for which PSNH is deficient.  The costs of both the RECs and ACPs will not directly impact earnings, as these costs will be recovered by PSNH through its ES rates.


Massachusetts:  


Decoupling Decision:   On July 16, 2008, the DPU issued a decision in its decoupling generic docket requiring all gas and electric utilities to file full decoupling proposals with their next general rate case.  The decision rejected calls for partial decoupling or decoupling by rate design in favor of full decoupling by rate class.  Actual revenues are to be reconciled to target revenues, as established in litigated rate cases, on an annual basis.  Adjustments per the reconciliation will be made to the distribution component of rates.  The decision also determined that the DPU will honor existing long-term rate plans, performance-based regulation plans and settlements, but all utilities must file notices with the DPU by September 2, 2008 disclosing when they intend to file their next rate case.  


Basic Service Rates:  Effective July 1, 2008, the rates for basic service customers increased due to the rise in the cost of energy, which was reflected in WMECO's most recent basic service solicitations.  Basic service rates for residential and small commercial and industrial customers increased from 10.8 cents per KWH to 12.1 cents per KWH, and rates for medium and large commercial and industrial customers increased from 10.5 cents per KWH to 14.6 cents per KWH.  


Contingent Matters:  


The items summarized below contain contingencies that may have an impact on our net income, financial position or cash flows.  See Note 5A, "Commitments and Contingencies - Regulatory Developments and Rate Matters," to the condensed consolidated financial statements for further information regarding these matters.


·

CTA and SBC Reconciliation :  On March 31, 2008, CL&P filed with the DPUC its 2007 Competitive Transition Assessment (CTA) and System Benefits Charge (SBC) reconciliation, which compared CTA and SBC revenues to revenue requirements.  For the 12 months ended December 31, 2007, total CTA revenues exceeded CTA revenue requirements by $26.1 million, which has been recorded as a decrease to the CTA regulatory asset on the accompanying condensed consolidated balance sheets.  For the 12 months ended December 31, 2007, the SBC cost of service exceeded SBC revenues by $39.4 million, which has been recorded as a regulatory asset on the accompanying condensed consolidated balance sheets.  We expect a decision from the DPUC on this docket by the end of 2008 and do not expect the outcome to have a material adverse impact on CL&P's net income, financial position or cash flows.  


·

Procurement Fee Rate Proceedings:   CL&P submitted to the DPUC its proposed methodology to calculate the variable incentive portion of its procurement fee, which was effective through 2006, and requested approval of the pre-tax $5.8 million 2004 incentive fee.  CL&P has not recorded amounts related to the 2005 or 2006 procurement fee in earnings, although we estimate



64




that if CL&P’s methodology is upheld, CL&P would record in 2008 after-tax amounts of $3.3 million for 2006 and $3.6 million for 2005.


CL&P has recovered the $5.8 million pre-tax amount, which was recorded in 2005 earnings through the CTA reconciliation process.  If the DPUC does not allow recovery of $5.8 million for procurement fees in its final decision, then CL&P would record a loss and establish an obligation to refund this amount to its customers.  A date for the new draft decision in this docket has not yet been determined by the DPUC.  We believe that final regulatory approval of the $5.8 million pre-tax amount is probable.


·

ES and SCRC Reconciliation:  On May 1, 2008, PSNH filed its 2007 ES/SCRC reconciliation with the NHPUC.  Hearings are scheduled before the NHPUC in November 2008.  We do not expect the outcome of the NHPUC's review of this filing to have a material adverse impact on PSNH's net income, financial position or cash flows.


·

Transition Cost Reconciliations:  On July 18, 2008, WMECO filed its 2007 transition cost reconciliation with the DPU.  The schedule for reviewing this filing will be set by the DPU at a later date.   We do not expect the outcome of the DPU's review of this filing to have a material adverse effect on WMECO's net income, financial position or cash flows.


NU Enterprises Divestitures


We have exited most of our competitive businesses.  NU Enterprises continues to manage to completion its remaining wholesale marketing contracts and energy services activities.  


Wholesale Marketing:   In the first half of 2008, Select Energy continued to manage its remaining PJM power pool wholesale sales contract and its related supply contracts, which expired on May 31, 2008, and its long-term wholesale sales contract with the New York Municipal Power Agency (NYMPA), an agency comprised of municipalities, and related supply contracts, that expires in 2013.  These contracts are derivatives that have been marked to market through earnings.  In addition to the NYMPA-related contracts, Select Energy's only other long-term wholesale obligation is a non-derivative contract to purchase the output of a certain generating facility in New England through 2012.  As a non-derivative contract, the fair value of the contract has not been reflected on the balance sheet, and the contract has not been marked to market.  Based on the current estimated value of this non-derivative contract, when combined with the fair value of the derivative contracts in the NYMPA portfolio and cash collateral balances at June 30, 2008, we believe, under present conditions, that the estimated total net cash cost at June 30, 2008 to exit the remaining wholesale contracts if served out or settled at the same time is approximately break-even.  


Energy Services:  Most of NU Enterprises' energy services businesses were sold in 2005 and 2006.  Certain other businesses were wound down in 2007.  We continue to own and manage E.S. Boulos Company.  


In connection with the sale of the retail marketing business, the competitive generation business and certain of the energy services businesses, we provided various guarantees and indemnifications to the purchasers of those businesses.  See Note 5D, "Commitments and Contingencies - Guarantees and Indemnifications," to the condensed consolidated financial statements for information regarding these items.


NU Enterprises Contracts


Wholesale Derivative Contracts:   On January 1, 2008, we implemented SFAS No. 157.  For further information on SFAS No. 157, see Note 1C, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 3, "Fair Value Measurements," to the condensed consolidated financial statements, and the "Critical Accounting Policies and Estimates Update" section of this Management’s Discussion and Analysis.


At June 30, 2008 and December 31, 2007, the fair value of NU Enterprises' wholesale derivative assets and derivative liabilities (through its subsidiary Select Energy), which are subject to mark-to-market accounting, are as follows:


(Millions of Dollars)

 

June 30, 2008

 

December 31, 2007

Current wholesale derivative assets

 

$

22.1 

 

$

36.2 

Long-term wholesale derivative assets

 

 

22.5 

 

 

7.2 

Current wholesale derivative liabilities

 

 

(33.7)

 

 

(64.9)

Long-term wholesale derivative liabilities

 

 

(85.5)

 

 

(72.5)

Portfolio position

 

$

(74.6)

 

$

(94.0)


Numerous factors could either positively or negatively affect the realization of the wholesale derivative net fair value amounts in cash.  These factors include the volatility of commodity prices until the derivative contracts are exited or expire, differences between expected and actual volumes, the performance of counterparties, and other factors.



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Select Energy has policies and procedures requiring all of its wholesale derivative energy positions to be valued daily and segregating responsibilities between the individuals actually transacting (front office) and those confirming the trades (middle office).  The middle office is responsible for determining the portfolio's fair value independent from the front office.


The methods Select Energy used to determine the fair value of its wholesale derivative contracts are identified and segregated in the table of fair value of wholesale derivative contracts at June 30, 2008 and December 31, 2007.  A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange (NYMEX) futures and swaps that are marked to closing exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards and options, including bilateral contracts for the purchase or sale of electricity, and are marked to the mid-point of bid and ask market prices.  The mid-points of market prices are adjusted to include all applicable market information, such as prior contract settlements with third parties and bilateral contract prices in illiquid periods.  Currently, Select Energy also has a derivative contract for which a portion of the contract's fair value is determined based on a model.  The model utilizes natural gas prices and a conversion factor to electricity for off-peak periods in 2012 and all periods for 2013.  Broker quotes for electricity, at locations for which Select Energy has entered into transactions, are generally available through 2011 for on-peak and off-peak periods and through 2012 for on-peak periods.   


Generally, valuations of short-term derivative contracts derived from quotes or other external sources are more reliable should there be a need to liquidate the contracts, while valuations for longer-term derivative contracts are less certain.  Accordingly, there is a risk that derivative contracts will not be realized at the amounts recorded.


The tables below disaggregate the estimated fair value of the wholesale derivative contracts.  Valuations of individual contracts are broken into their component parts based upon prices actively quoted, prices provided by external sources and model-based amounts.  Under SFAS No. 157, contracts are classified in their entirety according to the lowest level for which there is at least one input that is significant to the valuation.  Therefore, these contracts are classified as Level 3 under SFAS No. 157.  At June 30, 2008 and December 31, 2007, the sources of the fair value of wholesale derivative contracts are included in the following tables:


 

 

Fair Value of Wholesale Contracts at June 30, 2008

(Millions of Dollars)

Sources of Fair Value

 

Maturity Less
than One Year

 

Maturity of One
to Four Years

 

Maturity in
Excess
of Four Years

 


Total Fair
Value

Prices actively quoted

 

$

5.9 

 

$

8.5 

 

$

0.6 

 

$

15.0 

Prices provided by external sources

 

 

(16.9)

 

 

(44.0)

 

 

(5.0)

 

 

(65.9)

Model-based (1)

 

 

(0.6)

 

 

(6.9)

 

 

(16.2)

 

 

(23.7)

Totals

 

$

(11.6)

 

$

(42.4)

 

$

(20.6)

 

$

(74.6)


 

 

Fair Value of Wholesale Contracts at December 31, 2007

(Millions of Dollars)

Sources of Fair Value

 

Maturity Less
than One Year

 

Maturity of One
to Four Years

 

Maturity in
Excess
of Four Years

 


Total Fair
Value

Prices actively quoted

 

$

(4.7)

 

$

(0.2)

 

$

1.4 

 

$

(3.5)

Prices provided by external sources

 

 

(24.0)

 

 

(38.8)

 

 

(13.4)

 

 

(76.2)

Model-based

 

 

 

 

4.3 

 

 

(18.6)

 

 

(14.3)

Totals

 

$

(28.7)

 

$

(34.7)

 

$

(30.6)

 

$

(94.0)


(1) The model-based amounts include the effects of implementing SFAS No. 157.


For the three and six months ended June 30, 2008, the changes in fair value of these contracts are included in the following table:


 

 

For the Three Months Ended
June 30, 2008

 

 

For the Six Months Ended
June 30, 2008

(Millions of Dollars)

 

Total Portfolio Fair Value

 

 

Total Portfolio Fair Value

 

 

 

 

 

 

 

Fair value of wholesale contracts outstanding at the beginning of the period

 

$

(81.1)

 

$

(94.0)

Pre-tax effects of implementing SFAS No. 157 ($3.7 million after-tax) (1)

 

 

 

 

(6.1)

Contracts realized or otherwise settled during the period (2)

 

 

8.8 

 

 

27.0 

Period change in unrealized losses included in earnings

 

 

(2.3)

 

 

(1.5)

Fair value of wholesale contracts outstanding at the end of the period

 

$

(74.6)

 

$

(74.6)


(1)

Pre-tax effect recorded in fuel, purchased and net interchange power on the condensed consolidated statement of income.

(2)

Amount includes purchases, issuances and settlements of $5.3 million and $20.7 million for the three and six months ended June 30, 2008, respectively, and realized intra-month gains of $3.5 million and $6.3 million for the three and six months ended June 30, 2008, respectively.



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For further information regarding Select Energy's derivative contracts, see Note 2, "Derivative Instruments," to the condensed consolidated financial statements.  


Counterparty Credit Risk:   Counterparty credit risk relates to the risk of loss that Select Energy would incur because of non-performance by counterparties pursuant to the terms of their contractual obligations.  Select Energy has established credit policies with regard to its counterparties to minimize overall credit risk.  These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash advances, LOCs, and parent guarantees), and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  This evaluation results in Select Energy establishing credit limits prior to entering into contracts.  The appropriateness of these limits is subject to our continuing review.  Concentrations among these counterparties may affect Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.  At June 30, 2008, approximately 84 percent of Select Energy's counterparty credit exposure to wholesale counterparties was non-rated, approximately 15 percent was rated BBB- or better and approximately one percent was collateralized.  The bulk of the non-rated credit exposure is comprised of one counterparty, which is a non-rated public entity that we believe to be creditworthy.  To date, this counterparty has met all of its contractual obligations.


Critical Accounting Policies and Estimates Update


The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and at times difficult, subjective or complex judgments.  Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial statements.  Our management communicates to and discusses with our Audit Committee of the Board of Trustees all critical accounting policies and estimates.  All of these critical accounting policies and estimates were reported in the 2007 Form 10-K.  There have been no material changes with regard to these critical accounting policies and estimates, except as follows:


Fair Value Measurements:  We adopted SFAS No. 157 as of January 1, 2008.  SFAS No. 157 defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price).  It establishes a framework for measuring fair value, using a three level hierarchy based upon the observability of inputs to the valuations.  See Note 1C, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 3, "Fair Value Measurements," to the accompanying condensed consolidated financial statements for further information.


As of January 1, 2008, we applied SFAS No. 157 to our regulated and unregulated companies’ derivative contracts that are recorded at fair value and to the marketable securities held in NU’s Rabbi Trust and WMECO’s prior spent nuclear fuel trust.  SFAS No. 157 also applies to investment valuations for our pension and other postretirement benefit plans beginning as of December 31, 2008, and beginning in 2009, to nonrecurring fair value measurements of non-financial assets and liabilities, such as goodwill and asset retirement obligations.  Implementing SFAS No. 157 for our marketable securities expanded our financial statement disclosures, but did not affect the recorded fair value of investments.  


In the first six months of 2008, we recorded an after-tax reduction of earnings of $2.4 million as a result of applying SFAS No. 157 to derivative liabilities for Select Energy’s remaining wholesale marketing contracts, net of a $1.3 million benefit from partially reversing the implementation charge as we served rather than exited these contracts during the period.


As a result of implementing SFAS No. 157, we also recorded changes in fair value of certain derivative contracts of CL&P.  Because CL&P is a cost-of-service, rate regulated entity, the cost or benefit of the contracts is expected to be fully recovered from or refunded to CL&P's customers, and an offsetting regulatory asset or liability was recorded to reflect these changes.  SFAS No. 157 resulted in a total increase to CL&P's derivative liabilities, with an offset to regulatory assets of approximately $590 million and a total decrease to derivative assets, with an offset to regulatory liabilities, of approximately $30 million.  The increase to CL&P's derivative liabilities primarily resulted from an increase in the negative fair value of a contract for differences with a generating plant to be built to reflect the estimated cost to exit this contract, reflecting an increase in the probability that the plant will be built and the recognition of a loss at the inception of the contract of approximately $100 million that was deferred under previous accounting guidance.  


If we do not exit but rather serve out our derivative liability contracts, we will not make payments for some portion of the negative fair value recorded for the contracts.  Likewise, we could receive more cash for derivative assets than the fair value recorded.


We use quoted market prices when available to determine fair values of financial instruments and classify those valuations as Level 1 within the fair value hierarchy.  If quoted market prices are not available, fair value is determined using quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments that are not active and model-derived valuations in which all significant inputs are observable.  These valuations are classified as Level 2 within the fair value hierarchy.  




67




Many of our derivative contracts that are recorded at fair value are classified as Level 3 within the hierarchy and are valued using models that incorporate both observable and unobservable inputs.  Fair value is modeled using techniques such as discounted cash flow approaches adjusted for assumptions relating to exit price and the Black-Scholes option pricing model, incorporating the terms of the contracts.  Significant unobservable inputs utilized in the valuations include energy and energy-related product prices for future years for long-dated derivative contracts, future contract quantities under full requirements and supplemental sales contracts, and market volatilities.  Discounted cash flow valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using available historical market transaction information.  Valuations of derivative contracts also reflect nonperformance risk, including credit risk.  Contracts valued using models are classified according to the lowest level for which there is at least one input that is significant to the valuation.  Therefore, an item may be classified as Level 3 even though there may be some significant inputs that are readily observable.  


Total Level 3 derivative assets were 76 percent of our total assets measured at fair value, and Level 3 derivative liabilities were 100 percent of our total liabilities measured at fair value at June 30, 2008.  A significant portion of our Level 3 derivative liabilities relate to the regulated company derivative contracts for which changes in fair value do not affect our earnings due to our use of regulatory accounting.  Changes in fair value of these contracts are not material to our liquidity or capital resources because the costs and benefits of the contracts are recoverable from or refundable to customers on a timely basis.


We review and update our fair value hierarchy classifications on a quarterly basis.  As of June 30, 2008, investment securities are classified in Levels 1 and 2.  Classifications of an investment security or group of investment securities into Level 3 may occur if a significant amount of inputs to their valuation is no longer observable due to a decline in market activity or liquidity.  


Changes in fair value of the remaining wholesale marketing contracts of our unregulated businesses are recorded in fuel, purchased and net interchange power on the accompanying condensed consolidated statements of income.  For the three and six months ended June 30, 2008, there were net unrealized losses of $1.4 million and $0.9 million, respectively, related to the valuation of these contracts.  For the three and six months ended June 30, 2008, there were net realized gains of $2.1 million and $3.8 million, respectively, related to the valuation of these contracts.  Key drivers of variability in fair values include changes in energy prices and expected volumes under the contracts.


Changes in fair value of the regulated company derivative contracts are recorded as regulatory assets or liabilities, as we expect to recover these costs in rates.  These valuations are sensitive to the prices of energy and energy related products in future years for which markets have not yet developed.  Assumptions made to implement SFAS No. 157 had a significant effect on derivative values, and changes in assumptions may continue to have significant effects.


For further information on derivative contracts, see Note 2, "Derivative Instruments," to the condensed consolidated financial statements.


Accounting for Environmental Reserves:  Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated.  Adjustments made to environmental reserves could have a significant effect on earnings.  Our approach estimates these liabilities based on the most likely action plan from a variety of available remediation options, ranging from no action to remedies ranging from establishing institutional controls to full site remediation and long-term monitoring.  The estimates associated with each possible action plan are based on findings through various phases of site assessments.


These estimates are based on currently available information from presently enacted state and federal environmental laws and regulations and several cost estimates from third-party engineering and remediation contractors who would be performing the work.  These estimates also take into consideration prior experience in remediating contaminated sites and data released by the United States Environmental Protection Agency and other organizations.  These estimates are subjective in nature partly because there are usually several different remediation options from which to choose when working on a specific site.  These estimates are subject to revisions in future periods based on actual costs or new information concerning either the level of contamination at the site or newly enacted laws and regulations.  The amounts recorded as environmental liabilities on the condensed consolidated balance sheets represent our best estimate of the liability for environmental costs based on current site information from site assessments and remediation estimates.  These liabilities are recorded on an undiscounted basis.  


Holyoke Water Power Company (HWP) is a subsidiary of NU that owns a minimal amount of transmission property and has limited operating activities.  HWP continues to evaluate additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with a manufactured gas plant which it sold to Holyoke Gas and Electric (HG&E), a municipal electric utility, in 1902.  HWP is at least partially responsible for this site, and has already conducted substantial remediation activities.  HWP first established a reserve for this site in 1994.  A pre-tax charge of approximately $3 million was recorded in the second quarter of 2008 to reflect the estimated cost of further tar delineation and site characterization studies, as well as certain remediation costs that are considered to be probable and estimable as of June 30, 2008.  The cumulative expense recorded to this reserve through June 30,



68




2008 was approximately $15.9 million, of which $12.6 million had been spent, leaving approximately $3.3 million in the reserve as of June 30, 2008.  


The Massachusetts Department of Environmental Protection (MA DEP) issued a letter on April 3, 2008 to HWP and HG&E, which shares responsibility for the site, providing conditional authorization for additional investigatory and risk characterization activities and providing detailed comments on HWP’s 2007 reports and proposals for further investigations.  MA DEP also indicated that further removal of tar in certain areas was necessary prior to commencing many of the additional studies and evaluation.  This letter represents guidance from the MA DEP, rather than mandates.  HWP is developing plans for additional investigations to accord with MA DEP’s guidance letter, including estimated costs and schedules.  These matters are subject to ongoing discussions with MA DEP and HG&E and may change from time to time.


At this time, we believe that the $3.3 million remaining in the reserve is at the low end of a range of probable and estimable costs of approximately $3.3 million to $4 million and will be sufficient for HWP to conduct the additional tar delineation and site characterization studies, evaluate its approach to this matter and conduct certain soft tar remediation.  The additional studies are expected to occur through 2008 and 2009, and possibly into 2010.  


There are many outcomes that could affect our estimates and require an increase to the reserve or range of costs, and a reserve increase would be reflected as a charge to pre-tax earnings.  However, we cannot reasonably estimate the range of additional investigation and remediation costs because they will depend on, among other things, the level and extent of the remaining tar that may be required to be remediated, the extent of HWP’s responsibility and the related scope and timing, all of which are difficult to estimate because of a number of uncertainties at this time.  As of June 30, 2008, HWP had $3.3 million remaining in the reserve related to this matter, and further developments may require a material increase to this reserve.


HWP's share of the remediation costs related to this site is not recoverable from customers.


Presentation:  In accordance with GAAP, our consolidated financial statements include all subsidiaries over which control is maintained and would include any variable interest entities (VIE) for which we are the primary beneficiary as defined in FASB Interpretation No. (FIN) 46(R), "Consolidation of Variable Interest Entities."  Determining whether we are the primary beneficiary of a VIE is complex and subjective, and requires our judgment.  There are a variety of facts and circumstances and a number of variables taken into consideration to determine whether we are considered the primary beneficiary of a VIE.  A change in facts and circumstances or a change in accounting guidance could require us to reconsider whether or not we are the primary beneficiary of the VIE.  


The Energy Independence Act required the DPUC to consider the impact on distribution companies of entering into long-term contracts for capacity and contracts to purchase renewable energy products from new generating plants.  We reviewed each contract to determine the appropriate accounting treatment based on the terms of the contracts.  Determining whether or not consolidation is required involves our judgment.


In April 2007, CL&P entered into a 15-year agreement beginning in 2010 to purchase energy, capacity and renewable energy credits from a biomass energy plant yet to be built.  In May 2008, CL&P and UI entered into six additional long-term agreements with proposed renewable energy plants.  As directed by the DPUC, CL&P has an agreement with UI under which it will share the costs and benefits of these contracts with 80 percent to CL&P and 20 percent to UI.  We evaluated whether entering into these contracts would require consolidation and determined that consolidation of the projects would not be required.  The review of these contracts required significant management judgment.  


In 2007, CL&P entered into two contracts for differences (CfDs) associated with the capacity of two generating projects to be built or modified and UI entered into two capacity-related CfDs, one with a generating project to be built and one with a new demand response project.  The contracts, referred to as CfDs, obligate the utilities to pay the difference between a set capacity price and the value that the projects receive in the ISO-NE capacity markets for periods of up to 15 years beginning in 2009.  As directed by the DPUC, CL&P has an agreement with UI under which it will share the costs and benefits of these four CfDs with 80 percent to CL&P and 20 percent to UI.  We determined that these contracts are derivatives and do not require consolidation.


The Energy Efficiency Act required electric distribution companies, including CL&P, and allowed others to file proposals with the DPUC to build cost-of-service peaking generation facilities.  On June 25, 2008, the DPUC issued a final decision approving three proposed peaking generation units totaling 678 MW of summer peaking capacity and rejecting nine others, including the two units proposed by CL&P.  In the third quarter of 2008, CfDs with the developers of the three approved units were signed or are expected to be signed, two by CL&P and one by UI.  As directed by the DPUC, CL&P and UI have entered into another sharing agreement, whereby CL&P is responsible for 80 percent and UI for 20 percent of the net costs or benefits of these CfD contracts.




69




The CfDs for peaking generation pay the developer the difference between floating capacity, forward reserve and energy market revenues, and a cost-of-service payment stream for 30 years.  The ultimate cost to CL&P under these contracts will depend on the costs of plant construction and operation and the prices that the projects receive for capacity and other products in the ISO-NE markets.  We are evaluating whether these contracts require consolidation.  Unlike the projects with which we have capacity CfDs, CL&P may be determined to be the primary beneficiary under the peaker CfDs and be required to consolidate these projects under the current requirements of FIN 46(R) because under the peaker CfDs, CL&P is required to reimburse the projects on a cost of service basis, which will result in CL&P absorbing more of the variability of the projects, including the costs of construction and operation.  Consolidation of these projects would likely result in significant increases to the property, plant and equipment and long-term debt balances on our consolidated balance sheets.  


The FASB is in the process of reinterpreting the consolidation requirements of FIN 46(R).  The expected guidance could eliminate the requirement for consolidation when we do not have the power to direct matters that significantly impact the plant’s activities.  CL&P and UI do not have this power over peaker plant operations, and it is possible that CL&P would not be required to consolidate the peaker projects if and when the new guidance becomes effective.  Changes in facts and circumstances and changes in accounting guidance resulting in reevaluation of the accounting treatment of these contracts could have a significant impact on the accompanying consolidated financial statements.


Other Matters


Contractual Obligations and Commercial Commitments:   For updated information regarding NU's contractual obligations and commercial commitments at June 30, 2008, see Note 5B, "Commitments and Contingencies - Long-Term Contractual Arrangements," to the condensed consolidated financial statements.  


Forward Looking Statements:   This discussion and analysis includes statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, financial performance or growth and other statements that are not historical facts.  These statements are "forward looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify these "forward looking statements" through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and similar expressions.  Forward looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance.  These expectations, estimates, assumptions or projections may vary materially from actual results.  Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward looking statements, including, but not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, changes in levels and timing of capital expenditures, developments in legal or public policy doctrines, technological developments, changes in accounting standards and financial reporting regulations, fluctuations in the value of our remaining competitive electricity positions, actions of rating agencies, and other presently unknown or unforeseen factors.  Other risk factors are detailed from time to time in our reports filed with the SEC and we encourage you to consult such disclosures.  


All such factors are difficult to predict, contain uncertainties which may materially affect our actual results and are beyond our control.  You should not place undue reliance on the forward-looking statements, each of which speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.  New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.  For more information, see "Risk Factors" included in this report and in our Annual Report on Form 10-K for the year ended December 31, 2007.  This Quarterly Report on Form 10-Q also describes material contingencies and critical accounting policies and estimates in the accompanying "Management’s Discussion and Analysis" and "Notes to Consolidated Financial Statements."  We encourage you to review these items.


Web Site:  Additional financial information is available through our web site at www.nu.com.




70




RESULTS OF OPERATIONS - NU CONSOLIDATED


The following table provides the variances in income statement line items for the condensed consolidated statements of income for NU included in this report on Form 10-Q for the three and six months ended June 30, 2008:


 

Income Statement Variances
(Millions of Dollars)
2008 over/(under) 2007

 

 

Second
Quarter

 

Percent

 

 

Six
Months

 

Percent

 

Operating Revenues:

$

(67)

 

(5)

%

 

$

(250)

 

(8)

%

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

Fuel, purchased and net interchange power

 

(143)

 

(18)

 

 

 

(390)

 

(21)

 

Other

 

(9)

 

(4)

 

 

 

40 

 

 

Maintenance

 

11 

 

18 

 

 

 

22 

 

21 

 

Depreciation

 

 

 

 

 

 

 

Amortization of regulatory assets/(liabilities), net

 

45 

 

(a)

 

 

 

68 

 

(a)

 

Amortization of rate reduction bonds

 

 

 

 

 

 

 

Taxes other than income taxes

 

 

 

 

 

 

 

Total operating expenses

 

(88)

 

(7)

 

 

 

(248)

 

(9)

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Income

 

21 

 

18 

 

 

 

(2)

 

(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

 

11 

 

 

 

10 

 

 

Other income, net

 

(2)

 

(13)

 

 

 

(2)

 

(8)

 

Income/(loss) from continuing operations
 before income tax (benefit)/expense

 

13 

 

19 

 

 

 

(14)

 

(8)

 

Income tax expense/(benefit)

 

 

 

 

 

(8)

 

(14)

 

Preferred dividends of subsidiary

 

 

 

 

 

 

 

Income/(loss) from continuing operations

 

12 

 

25 

 

 

 

(6)

 

(5)

 

Income/(loss) from discontinued operations

 

(3)

 

(100)

 

 

 

(1)

 

(100)

 

Net Income

$

 

19 

%

 

$

(7)

 

(6)

%


(a) Percent greater than 100.


Net income was $9 million higher in the second quarter of 2008 primarily due to the growth in the company's transmission segment and was $7 million lower for the six months primarily due to a $29.8 million after-tax charge associated with a litigation settlement.


Comparison of the Second Quarter of 2008 to the Second Quarter of 2007


Operating Revenues

Operating revenues decreased $67 million in 2008 primarily due to lower revenues from NU Enterprises ($40 million) and lower revenues from the regulated companies ($26 million).  NU Enterprises's revenues decreased $40 million due to the exit from components of the competitive businesses.  The lower regulated revenues were primarily due to the recovery of a lower level of CL&P distribution related expenses passed through to customers through regulatory tracking mechanisms.


Revenues from the regulated companies decreased $26 million due to lower distribution segment revenues ($43 million), partially offset by higher transmission segment revenues ($17 million).  Distribution segment revenues decreased $43 million primarily due to lower electric distribution revenues ($61 million), partially offset by higher gas distribution revenues ($18 million).  Transmission segment revenues increased $17 million primarily due to a higher transmission investment base, the impact of the March 24, 2008 FERC ROE decision and higher operating expenses which are passed through to customers under FERC-approved transmission tariffs.


Electric distribution revenues decreased $61 million due to the components of CL&P, PSNH and WMECO retail revenues which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($65 million), partially offset by the component of revenues which flows through to earnings, which increased $24 million.  The distribution revenue tracking components decreased $65 million primarily due to the pass-through of lower energy supply costs ($77 million), lower CL&P revenue associated with the recovery of delivery-related FMCC ($27 million) and a decrease in PSNH’s SCRC revenues mainly as a result of a rate decrease effective for 2008 ($12 million), partially offset by higher CL&P wholesale revenues primarily due to an increase in the market price of energy relating to sales of IPP generation to ISO-NE ($39 million).  The tracking mechanisms allow for



71




rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.


The distribution component of electric distribution segment revenues which flows through to earnings increased $24 million primarily due to increases in retail rates at each of the regulated companies ($28 million), partially offset by lower retail electric sales ($4 million).  Retail electric sales decreased by 4.5 percent in 2008 compared with 2007 (a 4.1 percent decrease on a weather normalized basis).  Firm gas sales increased 2.4 percent in 2008 compared with 2007 (a 7.4 percent increase on a weather normalized basis).


Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expenses decreased $143 million in 2008 due to lower costs at the regulated companies ($92 million) and lower expenses at NU Enterprises ($51 million).  Fuel expense from the regulated companies decreased primarily due to lower fuel, purchased and net interchange power expenses at CL&P and WMECO ($123 million), mainly due to a decrease in standard offer supply costs as a result of a reduction in load caused by customer migration to third party suppliers, partially offset by higher PSNH ($17 million) and Yankee Gas fuel expense ($14 million).  NU Enterprises' fuel expenses decreased due to the exit from certain components of the competitive businesses. 


Other Operation

Other operation expenses decreased $9 million in 2008 primarily due to lower regulated companies distribution and transmission segment expenses ($17 million), partially offset by higher NU Enterprises expenses ($8 million).  NU Enterprises expenses are higher by $8 million primarily due to higher operating costs at the remaining service businesses.  


Lower regulated company distribution and transmission segment expenses of $17 million are primarily due to lower CL&P distribution segment expenses related to transmission ($29 million), partially offset by higher CL&P Energy Independence Act (EIA) expenses which will be recovered through the FMCC deferral mechanism ($8 million).  


Maintenance

Maintenance expenses increased $11 million in 2008 primarily due to higher regulated company distribution expenses ($8 million), generation segment expenses as a result of the Merrimack Station Unit 2 maintenance outage ($2 million) and higher transmission line expenses ($1 million).  Regulated company distribution expenses are $8 million higher mainly as a result of higher tree trimming ($3 million), substation equipment ($1 million), line transformers ($1 million) and underground line activities ($1 million).  


Depreciation

Depreciation increased $5 million in 2008 primarily due to higher distribution and transmission depreciation expense as a result of higher plant balances from ongoing construction programs.


Amortization of Regulatory Assets/(Liabilities), Net

Amortization of regulatory assets/(liabilities), net increased $45 million in 2008 for the distribution segment primarily due to higher amortization at CL&P ($47 million) resulting from a higher recovery of transition costs ($34 million) and a credit in 2007 pertaining to the refund of the GSC over-recovery ($7 million).


Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $1 million in 2008.  The higher portion of principal within rate reduction bond payments resulted in a corresponding increase in the amortization of rate reduction bonds.  This increase was partially offset by a decrease at PSNH resulting from the retirement of $50 million of rate reduction bonds in January 2008.


Taxes Other than Income Taxes

Taxes other than income taxes increased $2 million in 2008 primarily due to higher CL&P and PSNH property taxes on higher plant balances.


Interest Expense, Net

Interest expense, net increased $6 million in 2008 primarily due to higher long-term debt interest ($6 million) resulting from the issuance of new long-term debt in 2007 and the first half of 2008 and higher short-term debt interest ($2 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($3 million).


Other Income, Net

Other income, net decreased $2 million in 2008 primarily due to lower investment income ($4 million) and EIA incentives ($1 million), partially offset by higher AFUDC equity ($3 million) mainly as a result of higher eligible construction work in progress and lower short-term debt resulting in an increase in the construction work in progress financed by permanent capital.




72




Income Tax Expense/(Benefit)

Income tax expense/(benefit) increased $1 million primarily due to higher CL&P pre-tax earnings related tax expense increases of ($5 million); partially offset by pre-tax expense decreases at NU Parent and other ($4 million).  NU projects its effective tax rate, excluding discrete items, to be in the range of 30-32 percent for the year, for purposes of estimating tax expense. These rates can fluctuate.  NU's current projected effective tax rate is lower than the statutory rate due primarily to temporary flow through depreciation benefits, Medicare subsidy and tax credits.


Income/(Loss) from Discontinued Operations

See Note 7, "Discontinued Operations," to the condensed consolidated financial statements for a description and explanation of the discontinued operations.


Comparison of the First Six Months of 2008 to the First Six Months of 2007


Operating Revenues

Operating revenues decreased $250 million in 2008 primarily due to lower revenues from the regulated companies ($170 million) and lower revenues from NU Enterprises ($80 million).  NU Enterprises's revenues decreased $80 million due to the exit from components of the competitive businesses.  The lower regulated revenues were primarily due to the recovery of a lower level of CL&P distribution related expenses passed through to customers through regulatory tracking mechanisms.


Revenues from the regulated companies decreased $170 million due to lower distribution segment revenues ($210 million), partially offset by higher transmission segment revenues ($40 million).  Distribution segment revenues decreased $210 million primarily due to lower electric distribution revenues ($243 million), partially offset by higher gas distribution revenues ($33 million).  Transmission segment revenues increased $40 million primarily due to a higher transmission investment base, the impact of the March 24, 2008 FERC ROE decision and higher operating expenses which are passed through to customers under FERC-approved transmission tariffs.


Electric distribution revenues decreased $243 million due to the components of CL&P, PSNH and WMECO retail revenues which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($246 million), partially offset by the component of revenues which flows through to earnings, which increased $44 million.  The distribution revenue tracking components decreased $246 million primarily due to the pass through of lower energy supply costs ($228 million) and lower CL&P revenue associated with the recovery of delivery-related FMCC ($61 million), partially offset by higher CL&P wholesale revenues primarily due to an increase in the market price of energy related to sales of IPP generation to ISO-NE ($48 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or under collections recovered from customers in future periods. 


The distribution component of the electric distribution segment which flows through to earnings increased $44 million primarily due to increases in retail rates at each of regulated companies ($54 million), partially offset by lower retail electric sales ($7 million).  Retail electric sales decreased by 3.1 percent in 2008 compared with 2007 (a 2.6 percent decrease on a weather normalized basis).  Firm gas sales decreased 2.6 percent in 2008 compared with 2007 (a 1.2 percent increase on a weather normalized basis).


Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expenses decreased $390 million in 2008 due to lower costs at the regulated companies ($296 million) and lower expenses at NU Enterprises ($94 million).  Fuel expense from the regulated companies decreased primarily due to lower fuel, purchased and net interchange power expenses at CL&P and WMECO ($327 million), mainly due to a decrease in standard offer supply costs as a result of a reduction in load caused by customer migration to third party suppliers, partially offset by higher Yankee Gas ($16 million) and PSNH fuel expense ($15 million).  NU Enterprises' fuel expenses decreased due to the exit from certain components of the competitive businesses. 


Other Operation

Other operation increased $40 million in 2008 primarily due to higher NU parent and other companies' expenses ($48 million), NU Enterprises expenses ($20 million), partially offset by lower regulated companies distribution and transmission segment expenses ($27 million).  NU parent and parent and other companies' expenses are higher by $48 million in 2008 primarily due to the $49.5 million payment to Con Edison resulting from the settlement of litigation and NU Enterprises expenses are higher by $20 million primarily due to higher operating costs at the remaining service businesses.  


Lower regulated company distribution and transmission segment expenses of $27 million are primarily due to lower CL&P distribution segment expenses related to transmission ($44 million), partially offset by higher customer accounts expenses at CL&P, PSNH, WMECO and Yankee ($10 million) and CL&P higher EIA expenses which will be recovered through the FMCC deferral mechanism ($9 million).  




73




Maintenance

Maintenance expenses increased $22 million in 2008 primarily due to higher regulated company distribution expenses ($19 million), generation segment expenses related to the Merrimack Station Unit 2 maintenance outage ($2 million) and higher transmission line expenses ($2 million).  Regulated company distribution expenses are $19 million higher mainly as a result of higher tree trimming ($6 million), overhead line maintenance expenses due to more storm-related expenses ($6 million), substation equipment ($2 million), underground line activities ($2 million) and line transformers ($1 million).

 

Depreciation

Depreciation increased $9 million in 2008 primarily due to higher distribution and transmission depreciation expense as a result of higher plant balances from ongoing construction programs.  


Amortization of Regulatory Assets/(Liabilities), Net

Amortization of regulatory assets/(liabilities), net increased $68 million in 2008 for the distribution segment primarily due to higher amortization at CL&P ($67 million) resulting from a higher recovery of transition costs ($38 million), a credit in 2007 pertaining to the refund of the GSC provision for rate refunds ($15 million) and higher amortization of SBC ($15 million).


Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $2 million in 2008.  The higher portion of principal within the rate reduction bond payments results in a corresponding increase in the amortization of rate reduction bonds.  


Interest Expense, Net 

Interest expense, net increased $10 million in 2008 primarily due to higher long-term debt interest ($13 million) resulting from the issuance of new long-term debt in 2007 and the first half of 2008, and higher short-term debt interest ($3 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($5 million).


Other Income, Net

Other income, net decreased $2 million in 2008 primarily due to lower investment income ($11 million) mostly due to lower NU parent cash which is being invested as equity in the operating companies, partially offset by higher AFUDC equity ($9 million) mainly as a result of higher eligible construction work in progress and lower short-term debt resulting in an increase in the construction work in progress financed by permanent capital.


Income Tax Expense/(Benefit)

Income tax expense/(benefit) decreased $8 million;  $25 million from NU Parent and other including $20 million from the Con Edison settlement and $4 million from other pre-tax expense increases, partially offset by pre-tax earnings related tax expense increases at CL&P ($10 million), PSNH ($4 million) and YGS ($3 million).  NU projects its effective tax rate, excluding discrete items, to be in the range of 30-32 percent for the year, for purposes of estimating tax expense.  These rates can fluctuate.  NU's current projected effective tax rate is lower than the statutory rate due primarily to temporary flow through depreciation benefits, Medicare subsidy and tax credits.


Income/(Loss) from Discontinued Operations

See Note 7, "Discontinued Operations," to the condensed consolidated financial statements for a description and explanation of the discontinued operations.




74




THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES


Management's Discussion and Analysis of
Financial Condition and Results of Operations


CL&P is a wholly owned subsidiary of NU.  This discussion should be read in conjunction with NU's Management's Discussion and Analysis of Financial Condition and Results of Operations, condensed consolidated financial statements and footnotes in this Form 10-Q, the First Quarter 2008 Form 10-Q and the NU 2007 Form 10-K.  


RESULTS OF OPERATIONS


The following table provides the variances in income statement line items for the condensed consolidated statements of income for CL&P included in this report on Form 10-Q for the three and six months ended June 30, 2008:


 

Income Statement Variances
(Millions of Dollars)
2008 over/(under) 2007

 

 

Second
Quarter

 

Percent

 

 

Six
Months

 

Percent

 

Operating Revenues:

$

(48)

 

(6)

%

 

$

(207)

 

(11)

%

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

Fuel, purchased and net interchange power

 

(118)

 

(23)

 

 

 

(313)

 

(26)

 

Other Operation

 

(11)

 

(8)

 

 

 

(16)

 

(6)

 

Maintenance

 

 

13 

 

 

 

11 

 

23 

 

Depreciation

 

 

 

 

 

 

 

Amortization of regulatory assets, net

 

47 

 

(a)

 

 

 

67 

 

(a)

 

Amortization of rate reduction bonds

 

 

 

 

 

 

 

Taxes other than income taxes

 

 

 

 

 

 

 

Total operating expenses

 

(74)

 

(9)

 

 

 

(243)

 

(14)

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Income

 

26 

 

40 

 

 

 

36 

 

26 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

 

10 

 

 

 

 

 

Other income, net

 

 

39 

 

 

 

 

70 

 

Income before income tax

 

25 

 

66 

 

 

 

42 

 

48 

 

Income tax expense

 

 

37 

 

 

 

10 

 

39 

 

Net Income/(Loss)

$

20 

 

79 

%

 

$

32 

 

52 

%


(a) Percent greater than 100.  


Comparison of the Second Quarter of 2008 to the Second Quarter of 2007


Operating Revenues

Operating revenues decreased $48 million in 2008 due to lower distribution segment revenues ($72 million), partially offset by higher transmission segment revenues ($24 million).


The distribution segment revenues decreased $72 million primarily due to the components of revenues, which are included in DPUC approved tracking mechanisms that track the recovery of certain incurred costs ($73 million).  The distribution segment revenue tracking components decreased $73 million primarily due to a decrease in revenues associated with the recovery of generation service and related congestion charges ($88 million) and delivery-related FMCC ($27 million), partially offset by higher wholesale revenues ($39 million).  The lower generation service and related congestion charge revenue was primarily due to a reduction in load caused primarily by customer migration to third party suppliers as well as lower congestion costs in 2008.  The lower delivery-related FMCC revenue was primarily due to a decrease in this rate component in 2008 as a result of lower reliability must run (RMR), VAR support and southwest Connecticut energy resource costs in 2008, as well as a larger prior year over-recovery being refunded to customers in 2008 as compared to 2007.  The higher wholesale revenue was primarily due to an increase in the market price of energy relating to sales of IPP generation to ISO-NE.  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.




75




The distribution component of revenues which impacts earnings increased $19 million primarily due to the rate increase effective February 1, 2008, partially offset by lower retail sales.  Retail sales decreased 5.8 percent in 2008 compared to the same period in 2007.


Transmission segment revenues increased $24 million primarily due to a higher transmission investment base, the impact of the March 24, 2008 FERC ROE decision and higher operating expenses which are passed through to customers under FERC-approved transmission tariffs.


Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $118 million primarily due to a decrease in deferred fuel costs ($62 million), a decrease in generation service supply costs ($54 million) and lower other purchased power costs ($2 million), all of which are included in DPUC approved tracking mechanisms.  The $62 million decrease in deferred fuel costs was primarily due to the combined effect of CL&P having a supply and delivery-related net FMCC over-recovery in the second quarter of 2007 and a supply and delivery-related net FMCC under-recovery in the second quarter of 2008.  The $54 million decrease in supply costs was primarily due to a reduction in load caused primarily by customer migration to third party suppliers.  These supply costs are the contractual amounts the company must pay to various suppliers that have earned the right to supply SS and LRS load through a competitive solicitation process.  


Other Operation

Other operation expenses decreased $11 million primarily due to lower distribution segment expenses relating to transmission ($29 million), partially offset by higher EIA expenses which will be recovered through the FMCC deferral mechanism ($8 million), higher storm expenses ($5 million), and higher administrative and general expenses ($3 million) primarily related to higher outside service costs.  


Maintenance

Maintenance expenses increased $4 million in 2008 primarily due to higher tree trimming expenses ($2 million) and higher transmission substation expenses ($1 million).


Depreciation

Depreciation expense increased $1 million primarily due to higher utility plant balances resulting from ongoing construction programs.


Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $47 million primarily due to a higher recovery of transition costs ($34 million), a credit in 2007 pertaining to the refund of the GSC over-recovery ($7 million) and higher amortization of SBC ($7 million).


Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $2 million.  The higher portion of principal within the rate reduction bonds’ payment results in a corresponding increase in the amortization of regulatory assets.


Taxes Other Than Income Taxes

Taxes other than income taxes increased $1 million primarily due to higher property taxes on higher plant balances.


Interest Expense, Net

Interest expense, net increased $4 million primarily due to higher long-tem debt ($4 million) interest resulting from the $200 million new debt issuance in September 2007 and the $300 million debt issuance in May 2008, higher short-term debt interest ($1 million) and higher FMCC deferral interest ($1 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($2 million).


Other Income, Net

Other income, net increased $3 million primarily due to higher equity AFUDC income ($3 million) as a result of higher eligible CWIP due to the transmission construction program resulting in an increase in CWIP financed by equity, and higher EIA incentives income ($1 million), partially offset by a higher investment loss ($2 million).


Income Tax Expense

Income tax expense increased $5 million primarily due to higher pre-tax earnings being subject to tax at marginal rates, partially offset by flow through impacts associated with depreciation and bad debt reserve changes.




76




Comparison of the First Six Months of 2008 to the First Six Months of 2007


Operating Revenues

Operating revenues decreased $207 million in 2008 due to lower distribution segment revenues ($252 million), partially offset by higher transmission segment revenues ($45 million).


The distribution segment revenues decreased $252 million primarily due to the components of revenues, which are included in DPUC approved tracking mechanisms that track the recovery of certain incurred costs ($250 million).  The distribution segment revenue tracking components decreased $250 million primarily due to a decrease in revenues associated with the recovery of generation service and related congestion charges ($241 million) and delivery-related FMCC ($61 million), partially offset by higher wholesale revenues ($48 million).  The lower generation service and related congestion charge revenue was primarily due to a reduction in load caused primarily by customer migration to third party suppliers as well as lower congestion costs in 2008.  The lower delivery-related FMCC revenue was primarily due to a decrease in this rate component in 2008 as a result of lower RMR, VAR support and southwest Connecticut energy resource costs in 2008, as well as a larger prior year over-recovery being refunded to customers in 2008 as compared to 2007.  The higher wholesale revenue was primarily due to an increase in the market price of energy relating to sales of IPP generation to ISO-NE.  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.


The distribution component of revenues which impacts earnings increased $32 million primarily due to the rate increase effective February 1, 2008, partially offset by lower retail sales.  Retail sales decreased 4 percent in 2008 compared to the same period in 2007.


Transmission segment revenues increased $45 million primarily due to a higher transmission investment base, the impact of the March 24, 2008 FERC ROE decision and higher operating expenses which are passed through to customers under FERC-approved transmission tariffs.


Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $313 million primarily due to a decrease in generation service supply costs ($195 million),  a decrease in deferred fuel costs ($109 million) and lower other purchased power costs ($9 million), all of which are included in DPUC approved tracking mechanisms.  The $195 million decrease in supply costs was primarily due to a reduction in load caused primarily by customer migration to third party suppliers.  These supply costs are the contractual amounts the company must pay to various suppliers that have earned the right to supply SS and LRS load through a competitive solicitation process.  The $109 million decrease in deferred fuel costs was primarily due to the combined effect of CL&P having a supply and delivery-related net FMCC over-recovery in the first six months of 2007 and a supply and delivery-related net FMCC under-recovery in the first six months of 2008.


Other Operation

Other operation expenses decreased $16 million primarily due to lower distribution segment expenses relating to transmission ($44 million), partially offset by higher EIA expenses which will be recovered through the FMCC deferral mechanism ($9 million), higher storm expenses ($5 million), higher administrative and general expenses primarily related to higher outside service costs ($4 million), higher Summer Saver Rewards Program expenses which will be recovered through the SBC deferral mechanism ($3 million), and higher distribution line expenses ($2 million).  


Maintenance

Maintenance expenses increased $11 million in 2008 primarily due to higher tree trimming expenses ($4 million), higher distribution line ($3 million), higher transmission substation equipment ($2 million), and higher line transformer activities ($1 million).


Depreciation

Depreciation expense increased $2 million primarily due to higher utility plant balances resulting from ongoing construction programs.


Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $67 million primarily due to a higher recovery of transition costs ($38 million), a credit in 2007 pertaining to the refund of the GSC over-recovery ($15 million) and higher amortization of SBC ($15 million).


Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $5 million.  The higher portion of principal within the rate reduction bonds’ payment results in a corresponding increase in the amortization of regulatory assets.




77




Taxes Other Than Income Taxes

Taxes other than income taxes increased $1 million primarily due to higher property taxes on higher plant balances.


Interest Expense, Net

Interest expense, net increased $3 million primarily due to higher long-term debt interest ($10 million) resulting from the $200 million debt issuance in September 2007, the $300 million debt issuance in March 2007 and the $300 million debt issuance in May 2008, partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($4 million) and lower debt AFUDC ($4 million).


Other Income, Net

Other income, net increased $9 million primarily due to higher equity AFUDC income ($8 million) as a result of higher eligible CWIP due to the transmission construction program and lower short term debt resulting in an increase in CWIP financed by equity, and higher EIA incentives income ($4 million), partially offset by a higher investment loss ($3 million).


Income Tax Expense

Income tax expense increased $10 million primarily due to higher pre-tax earnings being subject to tax at marginal rates, partially offset by flow through impacts associated with depreciation and bad debt reserve changes.


LIQUIDITY


CL&P had consolidated operating cash flows of $124 million, after rate reduction bond payments, in the first half of 2008, compared with operating cash flows of $157.8 million, after rate reduction bond payments but before tax payments of approximately $177.2 million related to the 2006 sale of NU's competitive generation business, in the first half of 2007.  Other drivers resulting in decreased operating cash flows in 2008 from 2007 are a reduction from regulatory refunds and underrecoveries (net of income tax impacts) and a net reduction in other working capital items, offset by a benefit from counterparty deposits.

 

CL&P projects consolidated operating cash flows of approximately $300 million to $350 million in 2008, after approximately $170 million of payments to retire CL&P's rate reduction bonds .   NU expects to receive a potential net income tax settlement of approximately $70 million in the second half of 2008 and a reduction in income tax payments of $35 million related to bonus depreciation adjustments over the remainder of the year, both of which would primarily effect the operating cash flows of CL&P.  


Cash capital expenditures included on the accompanying condensed consolidated statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, the AFUDC related to equity funds, and the capitalized portion of pension expense or income.  CL&P’s cash capital expenditures totaled $442 million in the first half of 2008, compared with $353.2 million in the first half of 2007.  This increase was primarily the result of higher transmission capital expenditures in 2008.  


On May 27, 2008, CL&P sold $300 million of first and refunding mortgage bonds due May 1, 2018 and carrying a coupon of 5.65 percent.  Proceeds from the issuance were used to repay short-term debt, and fund the company’s ongoing capital investment programs.


As of June 30, 2008, CL&P had no borrowings outstanding under the $400 million credit facility it shares with other NU subsidiaries.  In addition, CL&P had an arrangement with CRC and a financial institution under which the financial institution could purchase up to $100 million of CL&P's accounts receivable and unbilled revenues from CRC.  On June 30, 2008, there were no receivables sold under that facility and CL&P chose to terminate the Receivables Purchase and Sales Agreement due to the availability and relative cost of other liquidity sources.  At this time, CL&P has no further plans to securitize its accounts receivable and unbilled revenues and will utilize availability under its credit facility and other financing vehicles, as necessary, to fund its daily operating activities and capital programs.  


Other financing activities for the first half of 2008 included a first quarter 2008 capital contribution from NU parent of $57.1 million, offset by $53.2 million in common dividends paid to NU parent during the first half of 2008.  




78




PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES


Management’s Discussion and Analysis of

Financial Condition and Results of Operations


PSNH is a wholly owned subsidiary of NU.  This discussion should be read in conjunction with NU’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, condensed consolidated financial statements and footnotes in this Form 10-Q, the First Quarter 2008 Form 10-Q and the NU 2007 Form 10-K.


RESULTS OF OPERATIONS


The following table provides the variances in income statement line items for the condensed consolidated statements of income for PSNH included in this report on Form 10-Q for the three and six months ended June 30, 2008:


 

Income Statement Variances
(Millions of Dollars)
2008 over/(under) 2007

 

 

Second
Quarter

 

Percent

 

 

Six
Months

 

Percent

 

Operating Revenues:

$

24 

 

10 

%

 

$

38 

 

%

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

Fuel, purchased and net interchange power

 

17 

 

13 

 

 

 

16 

 

 

Other Operation

 

 

13 

 

 

 

 

 

Maintenance

 

 

29 

 

 

 

 

23 

 

Depreciation

 

 

 

 

 

 

 

Amortization of regulatory liabilities, net

 

(3)

 

(18)

 

 

 

 

 

Amortization of rate reduction bonds

 

(2)

 

(14)

 

 

 

(3)

 

(11)

 

Taxes other than income taxes

 

 

 

 

 

 

 

Total operating expenses

 

26 

 

12 

 

 

 

29 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Income

 

(2)

 

(5)

 

 

 

 

17 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

 

 

 

 

 

 

Other income, net

 

 

75 

 

 

 

 

86 

 

Income/(loss) before income tax

 

(2)

 

(7)

 

 

 

 

28 

 

Income tax expense

 

 

 

 

 

 

49 

 

Net Income/(Loss)

$

(2)

 

(10)

%

 

$

 

20 

%


(a) Percent greater than 100.  


Comparison of the Second Quarter of 2008 to the Second Quarter of 2007


Operating Revenues

Operating revenues increased $24 million in 2008 due to higher distribution segment revenues ($20 million) and higher transmission segment revenues ($4 million).


The distribution segment revenues increased $20 million primarily due to an increase of the components of revenues which are included in NHPUC approved tracking mechanisms that track the recovery of certain incurred costs ($17 million).  The distribution revenue tracking components increased $17 million primarily due to the pass-through of higher energy supply costs ($15 million), higher retail transmission revenues ($5 million), higher wholesale revenue ($7 million), partially offset by a decrease in the SCRC ($12 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.


The distribution component of PSNH’s retail revenues which impacts earnings increased $5 million as a result of the rate increases effective July 1, 2007 and January 1, 2008, partially offset by lower retail sales.  Retail sales decreased 1.0 percent in 2008 compared to the same period in 2007.


Transmission segment revenues increased $4 million primarily due to a higher transmission investment base, the impact of the March 24, 2008 FERC ROE decision and higher operating expenses which are passed through to customers under FERC-approved transmission tariffs.



79





Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power costs increased $17 million primarily due to higher forward energy market prices, partially offset by a decrease in payments to higher priced IPPs in 2008 as contracts expired.


Other Operation

Other operation expenses increased $6 million primarily due to higher retail transmission expenses ($3 million) which are tracked and recovered through the distribution retail transmission tracking mechanism, as well as higher customer accounts expenses ($3 million).


Maintenance

Maintenance expenses increased $7 million primarily due to higher generation segment expenses ($2 million) as a result of the Merrimack Station Unit 2 maintenance outage, distribution overhead lines ($2 million) and substation ($1 million) primarily due to more storms in the second quarter of 2008 compared to 2007 as well as expenditures associated with the REP which began July 1, 2007.


Depreciation

Depreciation expense increased $1 million primarily due to higher utility plant balances.


Amortization of Regulatory Liabilities, Net

Amortization of regulatory liabilities, net decreased $3 million primarily due to the reduction in net deferrals associated with PSNH's ES, TCAM and SCRC tracking mechanisms ($5 million), offset in part by the amortization related to the rate case settlement  effective July 1, 2007 ($2 million).  


Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds decreased $2 million primarily due to the retirement of $50 million of rate reduction bonds in January 2008.  


Interest Expense, Net

Interest expense, net increased $1 million primarily due to higher long-term debt interest as a result of the issuance of $70 million of first mortgage bonds in September 2007.  


Other Income, Net

Other income, net increased $1 million primarily due to a higher AFUDC, as a result of a higher eligible CWIP and lower short-term debt resulting in an increase in construction work in progress financed by equity and higher investment income.


Comparison of the First Six Months of 2008 to the First Six Months of 2007


Operating Revenues

Operating revenues increased $38 million due to higher distribution segment revenues ($31 million), and higher transmission segment revenues ($8 million).


The distribution segment revenues increased $31 primarily million due to an increase of the components of revenues which are included in NHPUC approved tracking mechanisms that track the recovery of certain incurred costs ($25 million).  The distribution revenue tracking components increased $25 million primarily due to the pass-through of higher energy supply costs ($22 million), higher retail transmission revenues ($11 million), higher wholesale revenues ($8 million), partially offset by a decrease in the SCRC ($24 million).  The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections recovered from customers in future periods.


The distribution component of PSNH’s retail revenues which impacts earnings increased $12 million as a result of the rate increases effective July 1, 2007 and January 1, 2008, partially offset by lower retail sales.  Retail sales decreased 0.5 percent in 2008 compared to 2007.


Transmission segment revenues increased $8 million primarily due to a higher transmission investment base, the impact of the March 24, 2008 FERC ROE decision and higher operating expenses which are passed through to customers under FERC-approved transmission tariffs.


Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power costs increased $16 million primarily due to higher forward energy market prices, partially offset by a decrease in payments to higher priced IPPs in 2008 as contracts expired.




80




Other Operation

Other operation expenses increased $6 million primarily due to higher retail transmission expenses ($7 million) which are tracked and recovered through the distribution retail transmission tracking mechanism, partially offset by lower administrative expenses ($2 million).  


Maintenance

Maintenance expenses increased $9 million primarily due to higher generation segment expenses ($2 million) as a result of the Merrimack Station Unit 2 maintenance outage, distribution overhead lines ($4 million) and substation ($1 million) and tree trimming ($1 million) primarily due to more storms in 2008 compared to 2007 as well as expenditures associated with the REP which began July 1, 2007.


Depreciation

Depreciation expense increased $1 million primarily due to higher utility plant balances.


Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds decreased $3 million primarily due to the retirement of $50 million of rate reduction bonds in January 2008.  


Interest Expense, Net

Interest expense, net increased $1 million primarily due to higher long-term debt interest as a result of the issuance of $70 million of first mortgage bonds in September 2007.


Other Income, Net

Other income, net increased $1 million primarily due to a higher AFUDC, as a result of a higher eligible CWIP and lower short-term debt resulting in an increase in construction work in progress financed by equity.


Income Tax Expense

Income tax expense increased $4 million due to higher pre-tax earnings and an increase in the effective tax rate.


LIQUIDITY


PSNH had consolidated operating cash flows of $27.8 million, after rate reduction bond payments of $24.4 million made during the first half of 2008, compared with operating cash flows of $27.1 million, after rate reduction bond payments of $25.5 million made in the first half of 2007.  The slight increase in 2008 operating cash flows was primarily due to a decrease in regulatory refunds and underrecoveries of approximately $3 million, offset by net payments of $1.7 million upon the termination of PSNH’s forward interest rate swap agreements related to its debt issuance of $110 million during the first half of 2008.  


Cash capital expenditures included on the accompanying condensed consolidated statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, the AFUDC related to equity funds, and the capitalized portion of pension expense or income.  PSNH’s cash capital expenditures totaled $119.2 million in the first half of 2008, compared with $79.5 million in the first half of 2007.  This increase was primarily the result of higher transmission capital expenditures in 2008.  


On May 27, 2008, PSNH sold $110 million of first mortgage bonds due May 1, 2018 and carrying a coupon of 6 percent.  Proceeds from the issuance were used to repay short-term debt and for general working capital purposes.  


As of June 30, 2008, PSNH had no borrowings outstanding under the $400 million credit facility it shares with other NU subsidiaries.  Other financing activities for the first half of 2008 included capital contributions from NU parent of $35.5 million and $18.2 million in common dividends paid to NU parent.




81




WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY


Management's Discussion and Analysis of
Financial Condition and Results of Operations


WMECO is a wholly owned subsidiary of NU.  This discussion should be read in conjunction with NU's Management's Discussion and Analysis of Financial Condition and Results of Operations, condensed consolidated financial statements and footnotes in this Form 10-Q, the First Quarter 2008 Form 10-Q and the NU 2007 Form 10-K.  


RESULTS OF OPERATIONS


The following table provides the variances in income statement line items for the condensed consolidated statements of income for WMECO included in this report on Form 10-Q for the three and six months ended June 30, 2008:


 

Income Statement Variances
(Millions of Dollars)
2008 over/(under) 2007

 

 

Second
Quarter

 

Percent

 

 

Six
Months

 

Percent

 

Operating Revenues:

$

(8)

 

(7)

%

 

$

(22)

 

(9)

%

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

Fuel, purchased and net interchange power

 

(5)

 

(9)

 

 

 

(14)

 

(11)

 

Other Operation

 

(3)

 

(10)

 

 

 

(8)

 

(16)

 

Maintenance

 

 

 

 

 

 

 

Depreciation

 

 

 

 

 

 

 

Amortization of regulatory assets, net

 

 

90 

 

 

 

 

52 

 

Amortization of rate reduction bonds

 

 

 

 

 

 

 

Taxes other than income taxes

 

 

 

 

 

 

 

Total operating expenses

 

(6)

 

(5)

 

 

 

(19)

 

(9)

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Income

 

(2)

 

(22)

 

 

 

(3)

 

(11)

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

 

 

 

 

 

 

Other income, net

 

 

 

 

 

 

 

Income/(loss) before income tax

 

(2)

 

(31)

 

 

 

(3)

 

(17)

 

Income tax expense/(benefit)

 

(1)

 

(34)

 

 

 

(1)

 

(18)

 

Net Income/(Loss)

$

(1)

 

(29)

%

 

$

(2)

 

(17)

%


Comparison of the Second Quarter of 2008 to the Second Quarter of 2007


Operating Revenues

Operating revenues decreased $8 million in 2008 compared to the same period in 2007 due to lower distribution segment revenues ($9 million), partially offset by higher transmission segment revenues ($1 million).  


The distribution segment revenues decreased $9 million primarily due to the components of revenues which are included in DPU approved tracking mechanisms that track the recovery of certain incurred costs.  The distribution revenue tracking components decreased $9 million primarily due to lower pension tracker and default service true-up revenues ($4 million), lower generation service revenue resulting from declining sales and load migration to competitive supply ($3 million) and lower retail transmission revenues ($3 million), partially offset by higher wholesale revenues ($2 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.


Transmission segment revenues increased $1 million primarily due to a higher transmission investment base, the impact of the March 24, 2008 FERC ROE decision and higher operating expenses which are passed through to customers under FERC-approved transmission tariffs.


Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $5 million primarily due to lower Basic Service supply costs resulting from declining sales and customer migration to competitive supply.  The Basic Service supply costs are the contractual amounts we must pay to various suppliers that serve Basic Service load after winning a competitive solicitation process.  




82




Other Operation

Other operation expenses decreased $3 million primarily due to lower administrative and general expenses ($2 million), mainly due to lower pension expense, which includes the regulatory deferral associated with the pension/PBOP tracker, and lower retail transmission expenses ($1 million).  The decrease in retail transmission expenses is primarily due to the deferral, resulting from the regulatory tracking mechanism, mainly as a result of the combination of lower retail transmission revenue and higher retail transmission expense caused by higher RMR and LNS expenses.


Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $2 million primarily due to the deferral of transition revenues collected in excess of allowed costs recovery, resulting mainly from lower power contract net costs.


Income Tax Expense/(Benefit)

Income tax expense/(benefit) decreased $1 million due to lower pre-tax earnings.


Comparison of the First Six Months of 2008 to the First Six Months of 2007


Operating Revenues

Operating revenues decreased $22 million in 2008 compared to the same period in 2007 due to lower distribution segment revenues ($23 million), partially offset by higher transmission segment revenues ($1 million).  


The distribution segment revenues decreased $23 million primarily due to the components of revenues which are included in DPU approved tracking mechanisms that track the recovery of certain incurred costs ($22 million).  The distribution revenue tracking components decreased $22 million primarily due to lower generation service revenue resulting from declining sales and load migration to competitive supply ($9 million), lower pension tracker and default service true-up revenues ($9 million) and lower retail transmission revenues ($6 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.


Transmission segment revenues increased $1 million primarily due to a higher transmission investment base, the impact of the March 24, 2008 FERC ROE decision and higher operating expenses which are passed through to customers under FERC-approved transmission tariffs.


Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $14 million primarily due to lower Basic Service supply costs resulting from declining sales and customer migration to competitive supply.  The Basic Service supply costs are the contractual amounts we must pay to various suppliers that serve Basic Service load after winning a competitive solicitation process.  


Other Operation

Other operation expenses decreased $8 million primarily due to lower retail transmission expenses ($4 million) and lower administrative and general expenses ($3 million), mainly due to lower pension expense, which includes the regulatory deferral associated with the pension/PBOP tracker.  The decrease in retail transmission expenses is primarily due to the deferral, resulting from the regulatory tracking mechanism, mainly as a result of the combination of lower retail transmission revenue and higher retail transmission expense caused by higher RMR and LNS expenses.


Maintenance

Maintenance expenses increased $1 million primarily due to higher distribution line maintenance.


Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $2 million primarily due to the deferral of transition revenues collected in excess of allowed costs recovery, resulting mainly from lower power contract net costs.


Income Tax Expense/(Benefit)

Income tax expense/(benefit) decreased $1 million due to lower pre-tax earnings.


LIQUIDITY


WMECO had positive consolidated operating cash flows of $31 million, after rate reduction bond payments of $6.9 million, in the first half of 2008, compared with negative operating cash flows of $12 million, after rate reduction bond payments of $6.4 million, in the first half of 2007.  The improvement in 2008 operating cash flows was primarily due to the payment of $47.9 million in federal and state income taxes in the first quarter of 2007, which was a result of the 2006 sale of our competitive generation business, offset by a decrease in regulatory overrecoveries of approximately $23 million.  



83





Cash capital expenditures included on the accompanying condensed consolidated statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, the AFUDC related to equity funds, and the capitalized portion of pension expense or income.  WMECO’s cash capital expenditures totaled $27.9 million in the first half of 2008, compared with $21.9 million in the first half of 2007.  This increase was primarily the result of higher transmission capital expenditures in 2008.  


As of June 30, 2008, WMECO had no borrowings outstanding under the $400 million credit facility it shares with other NU subsidiaries.  Other financing activities for the first half of 2008 included a capital contribution from NU parent of $16.3 million and $6.7 million in common dividends paid to NU parent.





84




ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


Market Risk Information


We utilize the sensitivity analysis methodology to disclose quantitative information for our commodity price risks (including where applicable capacity and ancillary components).  Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity price components, or other similar price changes.  Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity components, contract prices and market prices represented by each derivative contract.  For swaps, forward contracts and options, fair value reflects our best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments.  Exchange-traded futures and options are recorded at fair value based on closing exchange prices.  The fair value of our other contracts is based on models.  As Select Energy's contract volumes are winding down and are substantially hedged against price risks, the company has limited exposure to commodity price risks.  


Wholesale Portfolio: When conducting sensitivity analyses of the change in the fair value of the wholesale portfolio, which includes a non-derivative power purchase contract, which would result from a hypothetical change in the future market price of electricity, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments.


A hypothetical change in the fair value of the wholesale portfolio was determined assuming a 10 percent change in forward market prices.  At June 30, 2008, we calculated the market price resulting from a 10 percent change in forward market prices of those contracts.  A 10 percent increase in prices for all products would have resulted in a pre-tax increase in fair value of $3.5 million and a 10 percent decrease in prices for all products would have resulted in a pre-tax decrease in fair value of $3.7 million.  A 10 percent increase in energy prices would have resulted in a $4.1 million pre-tax decrease, and a 10 percent decrease in energy prices would have resulted in a $3.9 million pre-tax increase.  A 10 percent increase/(decrease) in capacity prices would have resulted in a $1.8 million pre-tax increase/(decrease).  A 10 percent increase/(decrease) in ancillary prices would have resulted in a $5.8 million pre-tax increase/(decrease).  


The impact of a change in electricity prices on wholesale transactions at June 30, 2008 are not necessarily representative of the results that will be realized, if such a change were to occur.  Also, energy, capacity and ancillaries have different market volatilities.  The derivative contracts in the wholesale portfolio are accounted for at fair value, and changes in market prices impact earnings.


Other Risk Management Activities


Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt.  At June 30, 2008, approximately 91 percent (85 percent including the long-term debt subject to the fixed-to-floating interest rate swap as variable rate long-term debt) of our long-term debt, including fees and interest due for spent nuclear fuel disposal costs, was at a fixed interest rate.  The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility.  Assuming a one percentage point increase in our variable interest rate, annual interest expense would have increased by a pre-tax amount of $3.7 million.  At June 30, 2008, we maintained a fixed-to-floating interest rate swap at NU parent to manage the interest rate risk associated with its $263 million of fixed-rate long-term debt.


Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations.  We serve a wide variety of customers and suppliers that include independent power producers (IPPs), industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers.  Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts.  This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms which, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.


Credit risks and market risks at NU Enterprises are monitored regularly by a Risk Oversight Council.  The Risk Oversight Council is comprised of individuals from outside of the management of these activities that create these risk exposures and functions to ensure compliance with our stated risk management policies.


We track and re-balance the risk in our portfolio in accordance with fair value and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure.


The NYMEX traded futures and option contracts cleared off the NYMEX exchange are ultimately guaranteed by NYMEX to Select Energy.  Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk on all



85




types of transactions.  These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash in advance, LOCs, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty.  This evaluation results in establishing credit limits prior to Select Energy entering into energy contracts.  The appropriateness of these limits is subject to continuing review.  Concentrations among these counterparties may impact Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.


At December 31, 2007, Select Energy had collateral balances deposited with counterparties of $18.9 million, which is included in current assets - prepayments and other on the accompanying condensed consolidated balance sheets.  There were no such deposits as of June 30, 2008.  At June 30, 2008, balances collected from counterparties resulting from Select Energy's credit management activities totaled $6.4 million, which is included in current liabilities - other on the accompanying condensed consolidated balance sheets.  There were no such balances as of December 31, 2007.


Our regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies.  Our regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and maintain an oversight group that monitors contracting risks, including credit risk.


We have implemented an Enterprise Risk Management (ERM) methodology for identifying the principal risks of the company.  ERM involves the application of a well-defined, enterprise-wide methodology that will enable our Risk and Capital Committee, comprised of our senior officers, to oversee the identification, management and reporting of the principal risks of the business.  However, there can be no assurances that the ERM process will identify every risk or event that could impact our financial condition or results of operations.  The findings of this process are periodically discussed with our Board of Trustees.


Additional quantitative and qualitative disclosures about market risk are set forth in Part I, Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," included in this combined report on Form 10-Q.


ITEM 4.

CONTROLS AND PROCEDURES


NU evaluated the design and operation of its disclosure controls and procedures at June 30, 2008 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Exchange Act and the rules and regulations of the SEC.  This evaluation was made under the supervision and with the participation of management, including NU’s principal executive officer and principal financial officer, as of the end of the period covered by this report on Form 10-Q.  The principal executive officer and principal financial officer have concluded, based on their review, that NU’s disclosure controls and procedures are effective to ensure that information required to be disclosed by NU in reports that it files under the Exchange Act (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.


There have been no changes in internal controls over financial reporting for NU during the quarter ended June 30, 2008 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.





86




PART II.  OTHER INFORMATION


ITEM 1.

LEGAL PROCEEDINGS


We are parties to various legal proceedings.  We have identified these legal proceedings in Part I, Item 3, "Legal Proceedings" and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2007.  There have been no material changes with regard to the legal proceedings previously disclosed in our most recent Form 10-K, as modified by our disclosure under Item 1, "Legal Proceedings" in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008.


ITEM 1A.

RISK FACTORS


NU is subject to a variety of significant risks in addition to the matters set forth under "Forward Looking Statements," in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Matters."  We have identified a number of these risk factors in our Annual Report on Form 10-K for the year ended December 31, 2007.  NU’s susceptibility to certain risks, including those discussed in detail in our Annual Report on Form 10-K, could exacerbate other risks.  These risk factors should be considered carefully in evaluating NU’s risk profile.  There have been no material changes with regard to the risk factors previously disclosed in our most recent Form 10-K.


ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS


There were no purchases made by or on behalf of NU or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934), of common stock during the quarter ended June 30, 2008.


ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS


At the Annual Meeting of Shareholders of NU held on May 13, 2008, the following twelve nominees were elected to serve on the Board of Trustees by the votes set forth below:


 

 

 

 

For

 

Withheld

 

Total

 

 

 

 

 

 

 

 

 

1. 

 

Richard M. Booth

 

129,311,675 

 

2,215,178 

 

131,526,853

2. 

 

John S. Clarkeson

 

129,119,827 

 

2,407,026 

 

131,526,853

3. 

 

Cotton M. Cleveland

 

121,813,909 

 

9,712,944 

 

131,526,853

4. 

 

Sanford Cloud, Jr.

 

129,311,494 

 

2,215,359 

 

131,526,853

5. 

 

James F. Cordes

 

129,381,529 

 

2,145,324 

 

131,526,853

6. 

 

E. Gail de Planque

 

128,018,467 

 

3,508,386 

 

131,526,853

7. 

 

John G. Graham

 

129,336,366 

 

2,190,487 

 

131,526,853

8. 

 

Elizabeth T. Kennan

 

128,534,094 

 

2,992,759 

 

131,526,853

9. 

 

Kenneth R. Leibler

 

129,256,587 

 

2,270,266 

 

131,526,853

10. 

 

Robert E. Patricelli

 

128,745,531 

 

2,781,322 

 

131,526,853

11. 

 

Charles W. Shivery

 

128,762,772 

 

2,764,081 

 

131,526,853

12. 

 

John F. Swope

 

128,784,128 

 

2,742,725 

 

131,526,853


NU's shareholders also ratified the Board of Trustees' selection of Deloitte & Touche LLP to serve as independent auditors of NU and its subsidiaries for 2008.  The vote ratifying such selection was 130,681,371 votes in favor and 472,802 votes against, with 372,680 abstentions.


CL&P:  In a written Consent in Lieu of an Annual Meeting of Stockholders of CL&P dated June 18, 2008, (CL&P Consent) the sole stockholder voted to fix the number of directors for the ensuing year at four and the following four directors were elected to serve on the Board of Directors for the ensuing year:  David R. McHale, Raymond P. Necci, Leon J. Olivier and Charles W. Shivery.  The vote on each of these proposals was 6,035,205 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of CL&P.  


WMECO:  In a written Consent in Lieu of an Annual Meeting of Stockholders of WMECO dated June 18, 2008 (WMECO Consent), the sole stockholder voted to fix the number of directors for the ensuing year at four and the following four directors were elected to serve on the Board of Directors for the ensuing year:  David R. McHale, Leon J. Olivier, Rodney O. Powell and Charles W. Shivery.  The vote on each of these proposals was 434,653 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of WMECO.  




87




PSNH:  In a written Consent in Lieu of an Annual Meeting of Stockholders of PSNH dated June 18, 2008 (PSNH Consent), the sole stockholder voted to fix the number of directors for the ensuing year at four and the following four directors were elected to serve on the Board of Directors for the ensuing year:  Gary A. Long, David R. McHale, Leon J. Olivier and Charles W. Shivery. The vote on each of these proposals was 301 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of PSNH.  





88




ITEM 6.

EXHIBITS


Each document described below is incorporated by reference by the registrant(s) listed to the files identified, unless designated with a (*), which exhibits are filed herewith.  


Exhibit No.

Description


Listing of Exhibits (NU)


4

Supplemental Indenture, dated as of June 1, 2008 between Northeast Utilities and The Bank of New York Trust Company, N.A., as Trustee relating to $250 million of Senior Notes, Series C, Due 2013 (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated June 5, 2008, File No. 001-5324)


*12

Ratio of Earnings to Fixed Charges


*15

Deloitte & Touche LLP Letter Regarding Unaudited Financial Information


*31

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 6, 2008


*31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 6, 2008


*32

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities and David R. McHale, Senior Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 6, 2008


Listing of Exhibits (CL&P)


4

Supplemental Indenture, dated as of May 1, 2008 to Indenture of Mortgage and Deed of Trust Dated as of May 1, 1921, as Amended and Restated as of April 7, 2005 by and between The Connecticut Light and Power Company and Deutsche Bank Trust Company Americas, as Trustee, relating to $300 million of 5.65% First and Refunding Mortgage Bonds, 2008 Series A, due 2018 (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated May 27, 2008, File No. 0-00404)


*4.1

Termination Agreement dated as of June 30, 2008, terminating the Amended and Restated Receivables Purchase and Sale Agreement among CL&P Receivables Corporation, CAFCO, LLC, Citibank, N.A., Citicorp North America, Inc., as Agent, and The Connecticut Light and Power Company


*12

Ratio of Earnings to Fixed Charges


*31

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 6, 2008


*31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 6, 2008


*32

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company and David R. McHale, Senior Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 6, 2008




89




Listing of Exhibits (PSNH)


*3

By-laws of PSNH, as in effect June 27, 2008


4

Sixteenth Supplemental Indenture, dated as of May 1, 2008, between PSNH and U.S. Bank National Association, Trustee, supplementing the First Mortgage Indenture, dated as of August 15, 1978, between the Company and U.S. Bank National Association as Trustee, relating to $110,000,000 its 6.00% First Mortgage Bonds, Series O, due 2018, (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated May 27, 2008 (File No. 001-06392)


*12

Ratio of Earnings to Fixed Charges


*31

Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 6, 2008


*31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 6, 2008


*32

Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire and David R. McHale, Senior Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 6, 2008


Listing of Exhibits (WMECO)


*12

Ratio of Earnings to Fixed Charges


*31

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 6, 2008


*31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 6, 2008


*32

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company and David R. McHale, Senior Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 6, 2008



 




90




SIGNATURE



Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.  



NORTHEAST UTILITIES

(Registrant)





By

/s/

David R. McHale

 

Date

 

David R. McHale

 

 

 

Senior Vice President and Chief Financial Officer

 

August 6, 2008

 

(for the Registrant and as Principal Financial Officer)

 

 



____________________________________________________________________________________

SIGNATURE



Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.  



THE CONNECTICUT LIGHT AND POWER COMPANY

(Registrant)





By

/s/

David R. McHale

 

Date

 

David R. McHale

 

 

 

Senior Vice President and Chief Financial Officer

 

August 6, 2008

 

(for the Registrant and as Principal Financial Officer)

 

 




91




SIGNATURE



Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.



PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

(Registrant)





By

/s/

David R. McHale

 

Date

 

David R. McHale

 

 

 

Senior Vice President and Chief Financial Officer

 

August 6, 2008

 

(for the Registrant and as Principal Financial Officer)

 

 



____________________________________________________________________________________

SIGNATURE



Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.  




WESTERN MASSACHUSETTS ELECTRIC COMPANY

(Registrant)





By

/s/

David R. McHale

 

Date

 

David R. McHale

 

 

 

Senior Vice President and Chief Financial Officer

 

August 6, 2008

 

(for the Registrant and as Principal Financial Officer)

 

 





92






Northeast Utilities

 

 

 

 

 

 

 

 

 

 

 

Exhibit 12

Ratio of Earnings to Fixed Charges

 

 

 

 

 

 

 

 

 

 

 

 

(In thousands)

 

Six Months
Ended

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2008

 

Year Ended December 31,

Earnings, as defined:

 

(unaudited)

 

2007

 

2006

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

 

 

 

 

 

 

   Net income/(loss) from continuing
     operations before cumulative effect of
     accounting change

 

$        116,241 

 

$        245,896 

 

$            132,936 

 

$         (256,903)

 

$       70,423 

 

$        77,105 

   Income tax expense/(benefit)

 

46,598 

 

109,420 

 

 (76,326)

 

 (184,862)

 

22,388 

 

19,751 

   Equity in earnings of regional nuclear
     generating and transmission companies

 

 (967)

 

 (3,983)

 

(334)

 

 (3,311)

 

 (2,592)

 

 (4,487)

   Dividends received from regional
     equity investees

 

341 

 

4,542 

 

2,145 

 

687 

 

3,879 

 

8,904 

   Fixed charges, as below

 

146,693 

 

275,611 

 

267,243 

 

265,046 

 

235,699 

 

228,974 

   Less: Interest capitalized
     (including AFUDC)

 

 (9,094)

 

 (17,568)

 

 (14,482)

 

 (10,463)

 

 (4,517)

 

 (5,030)

   Preferred dividend security requirements
    of consolidated subsidiaries

 

 (4,632)

 

 (9,265)

 

 (9,265)

 

 (9,265)

 

 (9,265)

 

 (9,265)

 Total earnings/(loss), as defined

 

$        295,181 

 

$        604,653 

 

$            301,917 

 

$         (199,071)

 

$     316,015 

 

$      315,952 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed charges, as defined:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

   Interest on long-term debt (a)

 

$          89,222 

 

$        162,841 

 

$            141,579 

 

$          131,870 

 

$     107,365 

 

$        88,700 

   Interest on rate reduction bonds

 

26,703 

 

61,580 

 

74,242 

 

87,439 

 

98,899 

 

108,359 

   Other interest (b)

 

12,776 

 

15,824 

 

22,375 

 

19,276 

 

8,586 

 

10,254 

   Rental interest factor

 

4,267 

 

8,533 

 

5,300 

 

6,733 

 

7,067 

 

7,366 

   Preferred dividend security requirements
   of  consolidated subsidiaries

 

4,632 

 

9,265 

 

9,265 

 

9,265 

 

9,265 

 

9,265 

   Interest capitalized (including AFUDC)

 

9,094 

 

17,568 

 

14,482 

 

10,463 

 

4,517 

 

5,030 

 Total fixed charges, as defined

 

$        146,693 

 

$        275,611 

$

$            267,243 

 

$          265,046 

 

$     235,699 

 

$      228,974 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of Earnings to Fixed Charges

 

2.01 

 

2.19 

 

1.13 

 

 (0.75)

(c)

1.34 

 

1.38 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Interest on long-term debt amounts include amortized premiums, discounts and capitalized expenses related to indebtedness.

 

 

(b)

For the six months ended June 30, 2008 and for the year ended December 31, 2007, other interest includes interest expense related to Financial Accounting Standards Board Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109."

 

(c)

Consolidated earnings were inadequate to cover fixed charges by $464.1 million for the year ended December 31, 2005.

 




Exhibit 15




August 6, 2008


Northeast Utilities

107 Selden Street

Berlin, Connecticut 06037


We have reviewed, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the unaudited condensed consolidated interim financial information of Northeast Utilities and subsidiaries (the "Company") for the three-month and six-month periods ended June 30, 2008 and 2007, as indicated in our report dated August 6, 2008 (which report includes an explanatory paragraph related to the adoption of Statement of Financial Accounting Standard No. 157, Fair Value Measurements , as of January 1, 2008); because we did not perform an audit, we expressed no opinion on that information.


We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, is incorporated by reference in Registration Statement Nos. 333-141425 on Form S-3 and Registration Statement Nos. 333-63144, 333-121364 and 333-142724 on Forms S-8.


We also are aware that the aforementioned report, pursuant to Rule 436(c) under the Securities Act of 1933, is not considered a part of the Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act.



/s/

Deloitte & Touche LLP

 

Deloitte & Touche LLP



Hartford, Connecticut



Exhibit 31


CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002


I, Charles W. Shivery, certify that:


1.

I have reviewed this quarterly report on Form 10-Q of Northeast Utilities (the registrant);


2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.




Date:  August 6, 2008




/s/

Charles W. Shivery

 

Charles W. Shivery

 

Chairman, President and Chief Executive Officer

 

(Principal Executive Officer)




Exhibit 31.1


CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002


I, David R. McHale, certify that:


1.

I have reviewed this quarterly report on Form 10-Q of Northeast Utilities (the registrant);


2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.




Date:  August 6, 2008




/s/

David R. McHale

 

David R. McHale

 

Senior Vice President and Chief Financial Officer

 

(Principal Financial Officer)




Exhibit 32


CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


In connection with the quarterly report of Northeast Utilities (the registrant) on Form 10-Q for the period ending June 30, 2008 as filed with the Securities and Exchange Commission (the Report), we, Charles W. Shivery, Chairman, President and Chief Executive Officer of the registrant and David R. McHale, Senior Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:


1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.




/s/

Charles W. Shivery

 

Charles W. Shivery

 

Chairman, President and Chief Executive Officer



/s/

David R. McHale

 

David R. McHale

 

Senior Vice President and Chief Financial Officer




Date:  August 6, 2008



A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.




Exhibit 4.1


TERMINATION AGREEMENT


TERMINATION AGREEMENT dated as of June 30, 2008 among CL&P RECEIVABLES CORPORATION, a Connecticut corporation (the "Seller"), CAFCO, LLC (the "Investor"), CITIBANK, N.A. (the "Bank"), CITICORP NORTH AMERICA, INC., as Agent (the "Agent") and THE CONNECTICUT LIGHT AND POWER COMPANY, as the Collection Agent (the "Collection Agent") and Originator (the "Originator").


PRELIMINARY STATEMENTS.


(A) The Seller, the Investor, the Bank, the Agent, and the Collection Agent and Originator are parties to an Amended and Restated Receivables Purchase and Sale Agreement dated as of March 30, 2001, as amended (the "RPA"). Terms not defined herein are used as defined in the RPA.


(B) The Seller desires (a) to make payment in full of all amounts due to the Agent, the Bank, the Investor and any other Person pursuant to the RPA, (b) to obtain UCC-3 termination statements in respect of each UCC-1 financing statement naming the Seller as debtor and filed in connection with the RPA (the "UCC-3 Statements"), and (c) to terminate the RPA.


NOW, THEREFORE, the parties hereto hereby acknowledge and agree as follows:


1. The parties hereby acknowledge there is not currently any outstanding Capital or Yield or any Receivable Interest under the RPA. The parties agree that on the Facility Termination Date, being the date hereof, the Seller shall pay to the Agent accrued but unpaid fees and all other amounts payable to the Agent, the Investor or the Bank under the RPA, in each case as set forth in Schedule I hereto. All amounts set forth in Schedule I shall be paid to the Agent no later than 12:00 noon (New York City time) on the Facility Termination Date, and shall be made in immediately available funds in U.S. Dollars by wire transfer to the Agent’s account.  This Agreement shall not be effective unless all such amounts are so received prior to such time.


2. Upon the Facility Termination Date, as provided in Section 1 above, the Purchase Limit and the Bank Commitment are each hereby terminated and the Agent, the Investor and the Bank hereby release as of the Facility Termination Date any and all security interests, liens or other encumbrances they may have in or to the Receivables or otherwise under the RPA, in each case without recourse to or representations or warranties of any kind by the Agent, the Investor or the Bank.


3. Upon the Facility Termination Date, as provided in Section 1 above, the RPA is terminated; provided, however, that, as contemplated by the RPA, the rights and remedies and provisions of the RPA referred to in Section 11.04(b) of the RPA shall survive such termination; and provided, further, that the Seller and the Collection Agent shall continue to be obligated to the Agent, the Investor and the Bank with respect to amounts constituting payments made in respect of the Seller's or the Collection Agent's respective liabilities and obligations under the RPA and the other Transaction Documents that are rescinded for any reason or must be otherwise restored by the Agent, the Investor or the Bank, whether as a result of any proceedings in bankruptcy or reorganization or otherwise



(and each of the Seller and the Collection Agent agrees that in any such case such liabilities or obligations shall be automatically reinstated).


4. The Seller further agrees to indemnify and hold harmless the Agent, the Investor and the Bank (each an "Indemnified Party") from and against any and all damages, losses, claims, liabilities and related costs and expenses including, without limitation, the reasonable fees and disbursements of counsel (all of the foregoing being collectively referred to as "Indemnified Amounts"), growing out of or resulting from this Agreement and any other documents delivered hereunder, excluding, however, (a) Indemnified Amounts to the extent resulting from gross negligence or willful misconduct on the part of such Indemnified Party, or (b) any income taxes incurred by such Indemnified Party arising out of or as a result of this Agreement and any other documents delivered hereunder. The Seller agrees to pay on demand all reasonable costs and expenses in connection with the preparation, execution, delivery and administration of this Agreement and any other documents to be delivered hereunder including, without limitation, the reasonable fees and out-of-pocket expenses of counsel for the Agent, the Investor and the Bank with respect thereto and with respect to advising the Agent, the Investor and the Bank as to the rights and remedies of each under this Agreement, and all reasonable costs and expenses, if any (including reasonable counsel fees and expenses), in connection with the enforcement of this Agreement and any other documents to be delivered hereunder.


5. The Agent agrees to execute and deliver such further documents and do such further acts as the Seller from time to time may reasonably request for the purpose of further evidencing, confirming, recording or otherwise documenting the termination contemplated by this Agreement, including delivering the UCC-3 Statements, subject to the Seller's payment on demand by the Agent and in full of the costs and expenses (including reasonable counsel fees and disbursements) of the Agent in connection therewith; provided, however, that no such party shall be required to take any action which exposes the Agent, the Investor or the Bank to liability or which is contrary to this Agreement or applicable law.


6. This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page to this Agreement by telecopier or by electronic mail in Portable Document Format (.pdf) shall be effective as delivery of a manually executed counterpart of this Agreement.


7. This Agreement shall be governed by, and construed in accordance with, the law of the State of New York.



In witness whereof, the undersigned parties have caused this Agreement to be duly executed by their authorized officers thereunto duly authorized as of the date first above written.


CL&P Receivables Corporation


 

By:

/s/

Randy A. Shoop

 

 

Name:

Randy A. Shoop

 

 

Title:

Vice President and Treasurer



CAFCO, LLC


 

By:

CitiCorp North America, Inc.

 

 

 

as Attorney in fact

 

 

 

 

 

By:

/s/ Eric Ripoli

 

 

 

Name:

Eric Ripoli

 

 

 

Title:

Vice President


Citibank, N.A.


 

 

By:

/s/ Eric Ripoli

 

 

 

Name:

Eric Ripoli

 

 

 

Title:

Vice President


Citicorp North America, Inc.


 

 

By:

/s/ Eric Ripoli

 

 

 

Name:

Eric Ripoli

 

 

 

Title:

Vice President


The Connecticut Light and Power Company


 

 

By:

/s/ Randy A. Shoop

 

 

 

Name:

Randy A. Shoop

 

 

 

Title:

Vice President and Treasurer









The Connecticut Light and Power Company

 

 

 

 

Exhibit 12

Ratio of Earnings to Fixed Charges

 

 

 

 

 

 

(In thousands)

 

Six Months
Ended

 

 

 

 

June 30, 2008

 

Year Ended December 31,

Earnings, as defined:

 

(unaudited)

 

2007

 

2006

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

 

 

 

 

 

 

 Net income

 

$          92,323 

 

$        133,564 

 

$        200,007 

 

$         94,845 

 

$          88,016 

 

$          68,908 

   Income tax expense/(benefit)

 

37,453 

 

52,353 

 

 (43,961)

 

32,174 

 

45,539 

 

18,135 

   Equity in (earnings)/losses of regional
    nuclear generating companies

 

 (200)

 

 (1,901)

 

854 

 

 (1,153)

 

 (568)

 

 (1,776)

   Dividends received from regional
     equity investees

 

 

2,596 

 

1,407 

 

412 

 

2,577 

 

6,359 

   Fixed charges, as below

 

81,168 

 

155,557 

 

131,923 

 

133,321 

 

119,857 

 

119,550 

   Less: Interest capitalized
     (including AFUDC)

 

 (6,697)

 

 (10,924)

 

 (6,610)

 

 (6,719)

 

 (3,110)

 

 (2,976)

 Total earnings, as defined

 

$        204,047 

 

$        331,245 

 

$        283,620 

 

$        252,880 

 

$        252,311 

 

$        208,200 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed charges, as defined:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

   Interest on long-term debt (a)

 

$         48,999 

 

$          84,292 

 

$          64,873 

 

$          59,019 

 

$          43,308 

 

$          39,815 

   Interest on rate reduction bonds

 

15,811 

 

37,728 

 

46,692 

 

55,796 

 

63,667 

 

70,284 

   Other interest (b)

 

6,561 

 

16,413 

 

6,281 

 

5,220 

 

3,072 

 

508 

   Rental interest factor

 

3,100 

 

6,200 

 

7,467 

 

6,567 

 

6,700 

 

5,967 

   Interest capitalized (including AFUDC)

 

6,697 

 

10,924 

 

6,610 

 

6,719 

 

3,110 

 

2,976 

 Total fixed charges, as defined

 

$          81,168 

 

$        155,557 

 

$        131,923 

 

$        133,321 

 

$        119,857 

 

$        119,550 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of Earnings to Fixed Charges

 

2.51 

 

2.13 

 

2.15 

 

1.90 

 

2.11 

 

1.74 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Interest on long-term debt amounts include amortized premiums, discounts and capitalized expenses related to indebtedness.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(b)

For the six months ended June 30, 2008 and for the year ended December 31, 2007, other interest includes interest expense related to Financial Accounting Standards Board Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109."





Exhibit 31


CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002


I, Leon J. Olivier, certify that:


1.

I have reviewed this quarterly report on Form 10-Q of The Connecticut Light and Power Company (the registrant);


2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.




Date:  August 6, 2008



/s/

Leon J. Olivier

 

Leon J. Olivier

 

Chief Executive Officer

 

(Principal Executive Officer)




Exhibit 31.1


CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002


I, David R. McHale, certify that:


1.

I have reviewed this quarterly report on Form 10-Q of The Connecticut Light and Power Company (the registrant);


2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.




Date:  August 6, 2008



/s/

David R. McHale

 

David R. McHale

 

Senior Vice President and Chief Financial Officer

 

(Principal Financial Officer)




Exhibit 32


CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


In connection with the quarterly report of The Connecticut Light and Power Company (the registrant) on Form 10-Q for the period ending June 30, 2008 as filed with the Securities and Exchange Commission (the Report), we, Leon J. Olivier, Chief Executive Officer of the registrant and David R. McHale, Senior Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:


1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.




/s/

Leon J. Olivier

 

Leon J. Olivier

 

Chief Executive Officer



/s/

David R. McHale

 

David R. McHale

 

Senior Vice President and Chief Financial Officer




Date:  August 6, 2008




A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.






Exhibit 3




















PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE



Organized Under the Laws of New Hampshire



August, 1926






____________________







BY-LAWS




As in effect June 27, 2008







____________________







BY-LAWS OF

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE



ARTICLE I.

Articles of Incorporation; Offices.



SECTION 1.  These By-Laws shall be subject to the Articles of Agreement or Articles of Incorporation of the corporation, whichever should then be in effect, and all references in these By-Laws to the Articles of Incorporation shall be construed to mean the Articles of Agreement or Articles of Incorporation of the corporation as from time to time amended.  


SECTION 2.  The corporation shall maintain its principal office in Manchester, New Hampshire, and may maintain offices at such other places as the Board of Directors (the "Board") may, from time to time, appoint.  


ARTICLE II.

Seal.


The initial corporate seal shall have inscribed thereon the name of the corporation and words and figures indicating the state and year of its incorporation.  The seal shall otherwise be in such form as the Board may determine.  After the merger of the corporation with and into Public Service Company of New Hampshire, the corporate seal shall have inscribed thereon the name Public Service Company of New Hampshire, the state of the corporation's incorporation, and 1926, the year of Public Service Company of New Hampshire's incorporation, and shall otherwise be in such form as the Board may determine.  If the seal of the corporation is at any time not available, a wafer seal may be used.  


ARTICLE III.

Capital Stock and Transfers.


SECTION 1.  The amount and classes of capital stock that may be issued by the corporation, and the designations, preferences, rights, privileges, voting powers, restrictions and qualifications of each class thereof, shall be as set forth in or pursuant to the Articles of Incorporation.  


SECTION 2.  Each holder of fully paid stock shall be entitled to a certificate or certificates of stock having plainly written or printed upon its face that the corporation is organized under the laws of The State of New Hampshire, the name of the person to whom issued and the number and class of shares represented by such certificate, and the designation of the series where a class is divided into series.  Stock certificates shall otherwise be in such form as the Board may from time to time prescribe; provided, however, that so long as the



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corporation is authorized to issue shares of more than one class each certificate shall set forth upon the face or back of the certificate, or shall state that the corporation will furnish to any shareholder upon request and without charge, a full statement of the designations, preferences, limitations, and relative rights of the shares of each class authorized to be issued and as to preferred shares, the variations in the relative rights and preferences between the shares of each series so far as the rights and preferences have been fixed and determined, and the authority of the Board to fix and determine the relative rights and preferences of subsequent series.  All stock certificates shall be sealed with the corporate seal, shall be signed by the President or any Vice President and by the Secretary or any Assistant Secretary of the corporation, and shall also be countersigned and registered by a Registrar to be appointed by the Board, and be countersigned by a Transfer Agent to be appointed by the Board; except that pending the preparation of permanent certificates the Board may cause temporary certificates to be issued; and except that the signatures of the above-named officers, and the corporate seal, and the signatures of the Transfer Agent or the Registrar, or both, may be facsimiles, engraved or printed.  


SECTION 3.  Shares of stock may be transferred by the owner by a writing upon the back of the certificate by him signed, or by a separate instrument of assignment, and the assignee, upon producing and surrendering to the corporation the former certificate so transferred or the certificate accompanied by such instrument, shall be entitled to a new certificate if no liens upon the stock against the former owner have attached.  The delivery of a stock certificate to a bona fide purchaser or pledgee for value, together with a written transfer of the same or a power of attorney to sell, assign and transfer the same, signed by the owner of the certificate, shall be a sufficient delivery to transfer the title; but no such transfer shall affect the right of the corporation to treat the stockholder of record as the stockholder in fact until the old certificate is surrendered and a new certificate is issued to the person entitled thereto.  Except as hereinafter provided, or as may be required by law or by the order of a court in appropriate proceedings, shares of stock shall be transferred on the books of the corporation only upon the proper assignment and surrender of the certificates issued therefor.  If an owner of stock claims that an outstanding stock certificate has been lost, destroyed, or wrongfully taken, such owner may upon request to the corporation have a new certificate issued to him provided he files with the corporation a sufficient indemnity bond or satisfies any other reasonable requirements imposed by the corporation.  


SECTION 4.  The transfer books may be closed by order of the Board for short periods, not exceeding twenty-five days at any



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one time, for the purpose of paying a dividend, or holding a meeting of stockholders, or for any other legal purpose, as the Board shall deem advisable.  


SECTION 5.  If default shall be made in the prompt payment when due of any sum payable to the corporation upon any subscription for stock of the corporation, and if such default shall continue for a period of thirty days after written demand has been made, then all rights under the subscription in and to the stock subscribed for shall, upon the expiration of such period, cease and determine and become and be forfeited to the corporation; provided that if at the expiration of such thirty-day period such right shall belong to the estate of a decedent, it may be forfeited only by resolution of the Board declaring forfeiture.  The corporation shall, within thirty-days after such forfeiture, cause such stock to be sold at private or public sale, at its market value at the time of sale, and shall, out of the net proceeds of sale and upon surrender of any outstanding Stock Subscription Receipt issued to evidence the subscription, pay to the recorded holder of such receipt the amount paid on the subscription prior to forfeiture, less the amount, if any, by which the total subscription price of the stock exceeded the net proceeds of sale.  


ARTICLE IV.

Meetings of Stockholders.


SECTION 1.  All meetings of the stockholders shall be held at the principal office of the corporation or at such other place within or without the State of New Hampshire as shall be designated in the call therefor.  An annual meeting shall be held each year on the second Thursday of May, or on such other date as the Board shall determine, but in no case later than June 30, at the time designated in the call, for the election of directors and the transaction of such other business as may come before it.

  

SECTION 2.  Special meetings of the stockholders may be called by vote of the Board, or on written request of stockholders holding not less than one-tenth in number of the total outstanding shares of capital stock of the corporation entitled to vote at the meeting, or as provided in the Articles of Incorporation, or in such other manner as may be provided by statute.  In case an annual meeting shall be omitted through inadvertence or otherwise, the business of such meeting may be transacted at a special meeting duly called for the purpose and in such case all references to the annual meetings in these By-Laws, except in Section 1 and this Section 2 of this Article IV, shall be deemed to refer to such special meeting held in place of the annual meeting.  


SECTION 3.  Notice of the time and place of each annual meeting shall be sent by mail to the recorded address of each



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stockholder entitled to vote thereat, or delivered in person to each such stockholder, not less than ten days nor more than fifty days (including the day of mailing or delivery) before the date of the meeting.  Like notice shall be given of all special meetings, except in cases where other special method of notice may be required by statute, in all which cases the statutory method shall be followed.  Except as otherwise provided in the Articles of Incorporation, notice of a stockholders' meeting need not be sent to any class of stockholders not entitled to vote upon any question to be acted upon or at any election of officers or directors to be held at such meeting.  The notice of stockholders' meeting shall state the objects of the meeting.  Less than ten days' notice of any stockholders' meeting shall be sufficient if all the stockholders entitled to vote at such meeting consent in writing to the notice actually given; and any meeting held without the notice herein provided for, and all action taken at such meeting, shall be legal and valid if all the stockholders entitled to notice thereof (a) are present in person or represented by proxy thereat and no objection is made by anyone so present, (b) waive notice thereof in writing, or (c) sign a written consent to the records thereof.  


SECTION 4.  At any meeting of stockholders, except where a different quorum is required by law, by the Articles of Incorporation or by these By-Laws, a representation in person or by proxy of a majority of the number of shares of stock outstanding and entitled to vote upon a question to be considered or at any election of officers or directors or a class of directors to be held at the meeting, shall be necessary to constitute a quorum for the consideration of such question or for such election, and in case a class of stock is entitled to vote upon a question or at an election as a separate class a representation of a majority of the number of outstanding shares of that class shall be necessary to constitute a quorum for action by that class, except that a majority vote of whatever stock shall be represented shall be sufficient for (a) adjourning from time to time until a quorum shall be obtained or (b) adjourning sine die.


SECTION 5.  When a quorum for the consideration of a question is present at any meeting a majority in interest of the stock represented at the meeting and entitled to vote upon the question shall decide the question, or in case two or more classes of stock are entitled to vote as separate classes upon such question a majority interest of the stock represented at the meeting of each such class shall determine the action of that class except in either case where a larger vote is specifically required by law, by the Articles of Incorporation or by these By-Laws.  When a quorum for an election is present at any meeting a plurality of the votes cast for any office shall elect to such office except where a larger vote is specifically required by law, by the Articles of Incorporation or by these By-Laws.



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SECTION 6.  Except as specifically provided in the Articles of Incorporation and these By-Laws, stockholders shall have one vote for each share of stock owned and entitled to vote.  Stockholders may vote either in person or by proxy in writing dated not more than eleven months before the meeting named therein which shall be filed with the Secretary at the meeting or any adjournment thereof before being voted.  Such proxies shall entitle the holders thereof to vote at any adjournment of such meeting but shall not be valid after the final adjournment of such meeting.  Every proxy shall be revocable at the pleasure of the stockholder executing it, except as otherwise provided therein and as permitted by law.


ARTICLE V.

Directors.


SECTION 1.  The property and business of the corporation shall be managed, subject to the terms of the Articles of Incorporation, these By-Laws and the votes of the shareholders, under the direction of a Board of one or more individuals.  Directors shall be elected by ballot, by a plurality vote of the stockholders entitled to vote and present in person or represented by proxy at each election, except (i) as otherwise provided in the Articles of Incorporation, (ii) as hereinafter provided with respect to the filling of vacancies, and (iii) for the election of directors by the holders of the Preferred Stock, when, in accordance with the Articles of Incorporation, they, voting separately as one class, shall be entitled to elect additional directors.  The number of positions on the Board of Directors for any year shall be fixed by resolution of the shareholders or of the Board of Directors, or, in the absence of such a resolution, shall be the number elected at the preceding Annual Meeting of Shareholders.  Except as otherwise provided in the Articles of Incorporation, each director shall hold office until the next annual meeting when chosen otherwise than at an annual meeting, and for the term of one year when chosen at an annual meeting, and in either case until his successor shall be elected and shall qualify.  The Board shall have and may exercise all its powers notwithstanding the existence of one or more vacancies in its number.


SECTION 2.  Any vacancy in the Board shall be filled by the affirmative vote of a majority of its remaining members though less than a quorum and each director so appointed shall hold office until his successor shall be elected by the stockholders, who may so elect a successor at the next annual meeting or at any duly called special meeting prior thereto, and shall qualify.


SECTION 3.  The Board may hold its meetings and may have one or more offices, and may keep the books of the corporation (except such records and books as by the laws of New Hampshire



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are required to be kept within that State) within or outside of New Hampshire, at such places as it may from time to time determine.  In addition to the powers and authorities by these By-Laws, the Articles of Incorporation, and applicable law expressly conferred upon it, the Board may exercise all such powers of the corporation, and do all such lawful acts and things as are not by law, by the Articles of Incorporation or by these By-Laws required to be exercised or done by the stockholders.


SECTION 4.  Without prejudice to the general powers conferred by, and subject to the limitations mentioned in, the last sentence of Section 3 of this Article V, it is hereby expressly declared that the Board shall have the following powers, that is to say:


1.

From time to time to make and change rules and regulations, not inconsistent with these By-laws, for the management of the corporation's business and affairs.


2.

From time to time, as and when and upon such terms and conditions as it may determine, to authorize the corporation to issue any part of the authorized capital stock of the corporation and fix the consideration for the issue and disposal thereof.


3.

To cause the corporation to purchase, or otherwise acquire for the corporation, any property, right or privilege which the corporation is authorized to acquire at such price or consideration, and generally on such terms or conditions as it shall think fit.


4.

At its discretion to cause the corporation to pay for any property or rights acquired, by the corporation, either wholly or partly in money, stock, bonds, debentures or other securities of the corporation.


5.

To cause the corporation to borrow money, to create, make and issue mortgages, bonds, deeds of trust, trust agreements and negotiable or transferable instruments and securities, secured by mortgage or otherwise, and to do every other act and thing necessary to effectuate the same.


6.

To appoint, and at its discretion remove or suspend, any and all officers, employees and agents, permanently or temporarily, as it may think fit and to the fullest extent permitted by then applicable law, and to determine their duties and fix and from time to time change their duties, salaries and emoluments, and to require security in such instances and in such amounts as it thinks fit.


7.

To confer by resolution upon any officer of the corporation, the power to choose, remove or suspend subordinate officers, employees and agents.



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8.

To appoint any person or corporation to accept and hold in trust for the corporation, any property belonging to the corporation, or in which it is interested, or for any other purpose, and to execute and do all such deeds and things as may be requisite in relation to any such trust.


9.

To determine who shall be authorized on the corporation's behalf, to sign bills, notes, receipts, acceptances, endorsements, checks, releases, contracts and other paper and documents.


10.

To sell or otherwise dispose of any property of the corporation, the sale or disposal of which does not require a vote of the stockholders under the laws of The State of New Hampshire.


11.

To delegate any of the powers of the board in the course of the current business of the corporation to any standing or special committee, or to appoint any persons to be the agents of the corporation with such powers (including the powers to sub-delegate) and upon such terms as it shall think fit, to the fullest extent permitted by then applicable law.  


12.

To fix in advance a date for (1) any meeting of stockholders, (2) the payment of any dividend, (3) the making of any distribution to stockholders, (4) the last day upon which the consent or dissent of stockholders may be effectively expressed for any purpose, or (5) the delivery of evidences of rights or interests arising out of any issue, change, conversion or exchange of capital stock, as a record date for the determination of the stockholders entitled (a) to notice of and to vote at any meeting and any adjournment thereof, (b) to receive any dividend, (c) to receive any distribution to stockholders, (d) to consent or dissent for any purpose, or (e) to receive delivery of evidences of rights or interests arising out of any issue, change, conversion or exchange of capital stock, and in such case only stockholders of record on such record date shall have such rights notwithstanding any transfer of stock upon the books of the corporation after the record date.


13.

To direct the use of facsimile signatures of corporate officers of the corporation and a facsimile of the corporate seal, if any, upon bonds or other corporate obligations of the corporation for the payment of money where such bond or other obligation is authenticated or certified by a Trustee.




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ARTICLE VI.

Meetings of the Board.


SECTION 1.  Regular meetings of the Board shall be held at such place and time as may be designated from time to time by the Board; and such meetings, and a regular meeting immediately following and at the same place as each annual meeting of the stockholders, may be held without notice.  Special meetings of the Board may be called by the Chairman, if any, the Vice Chairman, if any, the President, or by any two directors.  Oral or written notice of the time and place of each special meeting of the Board of Directors shall be given to each director personally or by telephone, or by mail or facsimile at his last-known post office address, at least twenty-four hours prior to the time of the meeting, provided that any director may waive such notice in writing or by facsimile or by attendance at such meeting.


SECTION 2.  One-third of the Board then in office shall constitute a quorum for the transaction of business at any meeting of the Board.  A lesser number may adjourn any meeting from time to time, until a quorum is obtained, or may adjourn sine die.


SECTION 3.  In all meetings of the Board a majority vote of the members in attendance shall be decisive of all questions before the meeting, except as may be otherwise provided by law or by the Articles of Incorporation.  The Board shall keep minutes of the proceedings at its meetings.


SECTION 4.  Any resolution in writing concerning action to be taken by the Company, which resolution is approved and signed by all of the Directors, severally or collectively, whose number shall constitute a quorum for such action, shall have the same force and effect as if such action were authorized at a meeting of the Board of Directors duly called and held for that purpose, and such resolution, together with the Directors' written approval thereof, shall be recorded by the Secretary in the minute book of the Company.


SECTION 5.  A Director or a member of a committee of the Board of Directors may participate in a meeting of the Board of Directors or of such committee by means of conference telephone or similar communications equipment enabling all Directors participating in the meeting to hear one another, and participation in a meeting in such manner shall constitute presence in person at such meeting.


 

SECTION 6.  Directors of the corporation shall receive such salaries for services and such fees and expenses for attendance at meetings as may be fixed by resolution of the Board, and



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directors shall be entitled to be reimbursed for all actual expenses incurred for travel related to attendance at such meetings; provided, however, that no director, who is either an officer or a regular employee of the corporation and who receives compensation therefor, shall receive any compensation for service as a director or for attendance at meetings and provided further, that nothing herein contained shall be construed to preclude any director from serving the corporation in any other capacity, and receiving compensation therefor.


ARTICLE VII.

Executive Committee.


SECTION 1.  The Board may, by resolution passed by a majority of the whole Board, designate from its members an Executive Committee of such number, not less than three, as the Board may fix from time to time.  The Executive Committee may make its own rules of procedure and shall meet where and as provided by such rules, or by resolution of the Board.  One-third of the members of the Executive Committee shall constitute a quorum for the transaction of business.  During the intervals between the meetings of the Board, and except as provided by Section 8.25 of the New Hampshire Business Corporation Act, the Executive Committee shall have all the powers of the Board in the management of the business and affairs of the corporation, including power to authorize the seal of the corporation to be affixed to all papers which may require it, and, by majority vote of a quorum of its members, exercise any and all such powers in such manner as the Executive Committee shall deem best for the interests of the corporation, in all cases in which specific directions shall not have been given by the Board, and in which the vote of a quorum of the full Board is not required by law or by these By-Laws.


SECTION 2.  The Executive Committee shall keep regular minutes of its proceedings and report the same to the Board when required.  The Board shall have power to rescind any vote or resolution of the Executive Committee, but no such rescission shall have retroactive effect.


ARTICLE VIII.

Officers.


SECTION 1.  In each year there shall be elected by the Board

(i) a President, (ii) one or more Vice Presidents, (iii) a Secretary, (iv) one or more Assistant Secretaries, (v) a Treasurer, (vi) one or more Assistant Treasurers, and (vii) a Controller; and the Board may provide for and elect a Chairman, a Vice Chairman and such other officers and assistants and prescribe such duties for them as in its judgment may, from time to time, be required to conduct the business of the corporation.  The offices of President, Treasurer and/or Secretary may be held



-10-



by the same person, and one person may be both an assistant Treasurer and assistant Secretary.  All officers shall hold their respective offices for a term prescribed by the Board, and until their successors, willing to serve, shall have been elected and, in the case of the Secretary, qualified, unless sooner removed; but they, and any of them may be removed from their respective offices at the pleasure of the Board.  Vacancies arising in any office from any cause shall be filled by the Board; and the persons chosen to fill vacancies shall serve for the balance of the unexpired term and until their successors shall have been elected and, in the case of the Secretary, qualified.


SECTION 2.  The Board of Directors may provide for and elect a Chairman from its members and, if a Chairman is elected, the Board may designate whether the Chairman is to be an officer of the Company.  The Chairman, if and when elected, may elect, when present, to preside at meetings of the Board of Directors and of the Executive Committee.  He may attend any meeting of any committee of the Board, whether or not he is a member of such committee.  The Chairman, if an officer of the Company and when also elected or designated chief executive officer, shall have general supervision of the Company's affairs, and shall have such other powers and duties as may be prescribed by the Board of Directors.  Until a Chairman be elected or in case of the absence, death, resignation or removal from office of the Chairman, the powers and duties as such Chairman shall, for the time being, be exercised by the President, unless otherwise ordered by the Board of Directors.


SECTION 3.  A Vice Chairman, if and when elected, shall have such powers and duties as may from time to time be prescribed by the Board of Directors.  If the Chairman is unable at any time to attend to the duties of the office of Chairman, or in case of the Chairman's death, resignation or removal from office, the powers and duties of the Chairman shall, except as the Board of Directors may otherwise provide, devolve upon the Vice Chairman or, if more than one Vice Chairman is elected, the most senior Vice Chairman, and shall be exercised by such Vice Chairman during such inability of the Chairman or until the vacancy in the office of Chairman shall be filled.

 

SECTION 4.  Unless otherwise provided by the Board, the President shall have the general management and direction, subject to the control of the Board of Directors and of the Executive Committee and of the Chief Executive Officer or Chief Operating Officer, if such officers shall have been elected, of the business of the Company, including the power to appoint and to remove and discharge any and all agents and employees of the Company not elected or appointed directly by the Board of Directors.  He may, with the approval of the Board of Directors, appoint, to aid him in his duties, an assistant or assistants to be known by such title or titles as he may designate, and may



-11-



assign to such assistant or assistants such duties as he shall think advisable, not inconsistent with the By-Laws of the Company.


SECTION 5.  The Vice President, or Vice Presidents, if there shall be more than one, shall have such powers and duties as may from time to time be prescribed by the Board.  In case the President from absence or any other cause shall be unable at any time to attend to the duties of the office of President requiring attention, or in case of his death, resignation, or removal from office, the powers and duties of the President shall, except as the Board may otherwise provide, temporarily devolve upon the Vice President, if he shall be able to serve, if there shall be but one Vice President, or upon the highest ranking Vice President able to serve, if there shall be more than one, and shall be exercised by such Vice President as acting President during such inability of the President, or until the vacancy in the office of President shall be filled.  In case of the absence, disability, death, resignation or removal from office of both the President and the Vice Presidents, the Board shall elect one of its members to exercise the powers and duties of the President during such absence or disability, or until the vacancy in one of said offices shall be filled.


SECTION 6.  The Secretary shall be sworn each year to the faithful discharge of his duties, shall attend the meetings of and record all votes and proceedings of the stockholders and of the Board, shall make a record of all instruments and papers required to be recorded in his office and shall have the custody and care of the corporate seal, records and minutes of the corporation.  He shall keep or cause to be kept a suitable record of the addresses of stockholders and shall issue all notices for meetings of stockholders.  Whenever requested by the Chairman, if any, the Board or stockholders to give notice for a meeting of stockholders, he shall give such notice, as requested, and the notice shall state at whose request the notice is given.  Whenever requested by the Chairman, if any, the Vice Chairman, if any, the President, or by any two directors to give notice for a meeting of the Board, he shall give such notice, as requested, and the notice shall state at whose request the notice is given.  He shall sign all mortgages, and all other documents and papers to which his signature may be necessary or appropriate, shall affix the seal of the corporation to all instruments requiring the seal, and shall have such other powers and duties as are commonly incidental to the office of the Secretary, or as may be prescribed for him.  In the absence of the Secretary or an Assistant Secretary from any meeting of the stockholders or of the board, a Secretary pro tempore, who shall be similarly sworn, may be chosen to record the votes and proceedings thereat.

 

SECTION 7.  The Treasurer shall have charge of, and be responsible for, the collection, receipt, custody and



-12-



disbursement of the funds of the corporation, and shall deposit its funds in the name of the corporation, in, and shall transfer such funds so deposited between, such banks, trust companies, or safe deposit vaults as the Board may direct.  He shall have the custody of such books, receipted vouchers, and other books and papers as in the practical business operations of the corporation shall naturally belong in the office or custody of the Treasurer, or as shall be placed in his custody by the Board, by the Executive Committee, by the President, or by a Vice President when acting as President.  He shall also have charge of the safekeeping of all stock, bonds, mortgages, and other securities belonging to the corporation, but such stocks, bonds, mortgages, and other securities shall be deposited for safekeeping in a safe deposit vault to be approved by the Board or by the Executive Committee, in a box or boxes, access to which shall be had as may be provided by resolution of the Board or Executive Committee.  He shall have such powers and duties as are commonly incidental to the office of Treasurer, or as may be prescribed for him.  He may be required to give bond to the corporation for the faithful discharge of his duties in such form and to such amount and with such sureties as shall be determined by the Board.


SECTION 8.  The duties of the Controller shall be to maintain adequate records of all assets, liabilities, and transactions of the corporation; to see that adequate audits thereof are currently and regularly made; and, in conjunction with other officers and department heads, to initiate and enforce measures and procedures whereby the business of the corporation shall be conducted with the maximum safety, efficiency and economy.  Upon request of any member of the Board, he shall attend any meeting of the Board.  Upon request of any member of the Executive Committee, he shall attend any meeting of the Executive Committee.  


SECTION 9.  Assistant Secretaries, Treasurers or Controllers, when elected, shall assist the Secretary, the Treasurer or the Controller, as the case may be, in the performance of the respective duties assigned to such principal officers; and the powers and duties of any such principal officer, shall, except as otherwise ordered by the Board, temporarily devolve upon his assistant in case of the absence, disability, death, resignation or removal from office of such principal officer.  They shall perform such other duties as may be assigned to them from time to time.


SECTION 10.  In addition to the powers and duties of officers prescribed in these By-Laws and by law, and in addition to such powers and duties as the Board of Directors may prescribe but subject to such limitations as the Board of Directors may establish, each officer shall have the powers and perform the duties which by general usage pertain to the officer's particular office.



-13-




ARTICLE IX.

Miscellaneous.


SECTION 1.  Notes of the corporation shall be signed by the President or a Vice President and by the Treasurer or an

 Assistant Treasurer or by such officers or persons as may be designated from time to time by the Board.


SECTION 2.   No debts or obligations shall be contracted by any person on behalf of the corporation, unless authorized by the Board or the Executive Committee, except those incurred in the usual course of the business of the corporation.  


SECTION 3.  All dividends shall be payable at such time as may be fixed by the Board or by the Articles of Incorporation.  Before payment of any dividend or making any distribution of profits, there shall be set aside, out of the surplus or net profits of the corporation, such sum or sums as the Board from time to time, in its absolute discretion, thinks proper as a reserve fund to meet contingencies, or for equalizing dividends, or for repairing or maintaining any property of the corporation, or for such other purpose as the Board shall think conducive to the interest of the corporation.


SECTION 4.  The fiscal year of the corporation shall be the calendar year unless otherwise determined by the Board.  


SECTION 5.  The corporation shall indemnify, to the fullest extent permitted by applicable law, each person made or threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that such person or such person's testator or intestate is or was a director or officer of the corporation, or is or was serving, at the request of the corporation, for another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise in any capacity while he or she was such a director or officer, (hereinafter referred to as "Indemnified Person"), against expenses, including attorneys' fees, judgments, fines, penalties and amounts paid in settlement, actually and reasonably incurred in connection with such action or proceeding, or any appeal therein.


The corporation shall advance or promptly reimburse upon request any Indemnified Person for all expenses, including attorneys' fees, actually and reasonably incurred in defending any action or proceeding in advance of the final disposition thereof upon receipt of any undertaking then required by applicable law by or on behalf of such Indemnified Person.

 



-14-



Determinations with respect to indemnification and reimbursement of a person (unless ordered by a court) shall be made:  (1) by the Board acting (a) by majority vote or action of a disinterested quorum of directors; or (b) if such quorum is not obtainable, as directed by a majority vote or action of a committee of the Board, duly designated to act in the matter by a majority vote or action of the full Board (in which designation directors who are parties may participate), consisting solely of two or more directors not at the time parties to such proceeding; or (2) by independent legal counsel, selected by the Board or a committee thereof by vote or action as set forth in clauses (a) and (b) of clause (1), or if the requisite quorum of the full Board cannot be obtained therefor and such committee cannot be established, by a majority vote or action of the full Board (in which selection directors who are parties may participate); or (3) by a majority vote of the holders of the outstanding stock at the time entitled to vote for directors, voting as a single class; or (4) by any other method of determination selected by the Board (in which selection directors who are parties may participate).  


Nothing herein shall limit or affect any right of any Indemnified Person otherwise than hereunder to indemnification or expenses, including attorneys' fees, under any statute, rule, regulation, certificate of incorporation, by-law, insurance policy, contract or otherwise.


Anything in these By-Laws to the contrary notwithstanding, no elimination of this By-Law, and no amendment of this By-Law adversely affecting the right of any Indemnified Person to indemnification or advancement or reimbursement of expenses hereunder, shall be effective until the 60th day following the taking of such action, and no elimination of or amendment to this By-Law shall thereafter deprive any Indemnified Person of his or her rights hereunder arising out of alleged or actual occurrences, acts or failures to act occurring prior to such 60th day.  Upon taking any such action the corporation shall promptly notify all Indemnified Parties, which notification shall be sufficient if mailed, postage prepaid, to each such Indemnified Person at their last known address.


The corporation shall not, except by elimination or amendment of this By-Law in a manner consistent with the preceding paragraph and Article X of these By-Laws, and except by making any determination required by Section 5, IV, of the New Hampshire Business Corporation Act take any corporate action or enter into any agreement which prohibits, or otherwise limits the rights of any Indemnified Person to, indemnification in accordance with the provisions of this By-Law.  The indemnification of any Indemnified Person provided by this By-Law shall be deemed to be a contract between the corporation and such Indemnified Person and shall continue after such Indemnified



-15-



Person has ceased to be a director or officer of the corporation and shall inure to the benefit of such Indemnified Person's heirs, executors, administrators and legal representatives.  If the corporation fails timely to make any payment pursuant to the indemnification and advancement or reimbursement of expenses provisions of this Article IX Section 5 and an Indemnified Person commences an action or proceeding to recover such payment, the corporation in addition shall reimburse such Indemnified Person for the legal fees and other expenses of such action or proceeding if the Indemnified Party shall prevail in such action or proceeding.


In case any provision in this By-Law shall be determined at any time to be unenforceable in any respect, the other provisions shall not in any way be affected or impaired thereby.


For purposes of this By-Law, the corporation shall be deemed to have requested an Indemnified Person to serve an employee benefit plan where the performance by such Indemnified Person of his or her duties to the corporation also imposes duties on, or otherwise involves services by, such Indemnified Person to the plan or participants or beneficiaries of the plan.  Such Indemnified Person shall be indemnified against excise taxes assessed on him or her with respect to an employee benefit plan pursuant to applicable law.  For purposes of this Section 5 of Article IX of these By-Laws, the term "corporation" shall include any legal successor to the corporation, including any corporation which acquires all or substantially all of the assets of the corporation in one or more transactions.  


ARTICLE X.

Amendment.


The Board shall have the power to alter, amend or repeal these By-Laws or to adopt new By-Laws; provided,

however, that any such action shall be subject to repeal or change by action of the shareholders; and provided further that the unanimous vote of the Board shall be required to alter, amend, or repeal Article  IX, Section 5 of these By-Laws.  The By-Laws may contain any provisions for the regulation and management of the affairs of the corporation not inconsistent with law, or the Articles of Incorporation.  Action by the Board to alter, amend or repeal these By-Laws shall be by the affirmative vote of such number of directors as is equal to a majority of the full Board.









Public Service Company of New Hampshire

 

 

 

 

 

Exhibit 12

Ratio of Earnings to Fixed Charges

 

 

 

 

 

(In thousands)

 

Six Months
Ended

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2008

 

Year Ended December 31,

Earnings, as defined:

 

(unaudited)

 

2007

 

2006

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

 

 

 

 

 

 

 Net income

 

$          30,380 

 

$             54,434 

 

$             35,323 

 

$          41,739 

 

$        46,641 

 

$          45,624 

   Income tax expense

 

12,997 

 

22,794 

 

39,183 

 

12,234 

 

12,993 

 

29,773 

   Equity in (earnings)/losses of
     regional nuclear generating companies

 

 (35)

 

 (343)

 

74 

 

 (230)

 

 (165)

 

 (353)

   Dividends received from regional
     equity investees

 

 

521 

 

367 

 

172 

 

614 

 

1,219 

   Fixed charges, as below

 

26,428 

 

50,637 

 

50,092 

 

49,751 

 

47,211 

 

47,168 

   Less: Interest capitalized
      (including AFUDC)

 

 (1,623)

 

 (2,985)

 

 (2,768)

 

 (1,896)

 

 (272)

 

 (552)

 Total earnings, as defined

 

$          68,147 

 

$           125,058 

 

$           122,271 

 

$        101,770 

 

$      107,022 

 

$        122,879 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed charges, as defined:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

   Interest on long-term debt (a)

 

$          14,999 

 

$             26,029 

 

$             24,100 

 

$          20,481 

 

$        17,441 

 

$          15,408 

   Interest on rate reduction bonds

 

8,232 

 

18,013 

 

20,828 

 

24,074 

 

26,901 

 

29,081 

   Other interest

 

  890 

 

2,243 

 

829 

 

1,733 

 

1,197 

 

727 

   Rental interest factor

 

  684 

 

1,367 

 

1,567 

 

1,567 

 

1,400 

 

1,400 

   Interest capitalized (including AFUDC)

 

1,623 

 

2,985 

 

2,768 

 

1,896 

 

272 

 

552 

 Total fixed charges, as defined

 

$          26,428 

 

$             50,637 

 

$             50,092 

 

$          49,751 

 

$        47,211 

 

$          47,168 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of Earnings to Fixed Charges

 

2.58 

 

2.47 

 

2.44 

 

2.05 

 

2.27 

 

2.61 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

 Interest on long-term debt amounts include amortized premiums, discounts and capitalized expenses related to indebtedness.

 

 




Exhibit 31


CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002


I, Leon J. Olivier, certify that:


1.

I have reviewed this quarterly report on Form 10-Q of Public Service Company of New Hampshire (the registrant);


2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.




Date:  August 6, 2008



/s/

Leon J. Olivier

 

Leon J. Olivier

 

Chief Executive Officer

 

(Principal Executive Officer)




Exhibit 31.1


CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002


I, David R. McHale, certify that:


1.

I have reviewed this quarterly report on Form 10-Q of Public Service Company of New Hampshire (the registrant);


2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.




Date:  August 6, 2008




/s/

David R. McHale

 

David R. McHale

 

Senior Vice President and Chief Financial Officer

 

(Principal Financial Officer)




Exhibit 32


CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


In connection with the quarterly report of Public Service Company of New Hampshire (the registrant) on Form 10-Q for the period ending June 30, 2008 as filed with the Securities and Exchange Commission (the Report), we, Leon J. Olivier, Chief Executive Officer of the registrant, and David R. McHale, Senior Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:


1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.




/s/

Leon J. Olivier

 

Leon J. Olivier

 

Chief Executive Officer



/s/

David R. McHale

 

David R. McHale

 

Senior Vice President and Chief Financial Officer




Date:  August 6, 2008




A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.







Western Massachusetts Electric Company

 

Exhibit 12

Ratio of Earnings to Fixed Charges

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


(In thousands)

 

Six Months
Ended

 

 

 

 

June 30, 2008

 

Year Ended December 31,

Earnings, as defined:

 

(unaudited)

 

2007

2006

2005

2004

2003

 

 

 

 

 

 

 

 

 

 

 

 

 

 Net income

 

$                  9,569 

 

$                   23,604 

 

$                    15,644 

 

$                   15,085 

 

$                 12,373 

 

$                 16,212 

   Income tax expense

 

6,006 

 

14,586 

 

7,766 

 

9,294 

 

7,187 

 

11,687 

   Equity in (earnings)/losses of
     regional nuclear generating companies

 


(56)

 


 (526)

 


241 

 


 (311)

 


 (149)

 


 (473)

   Dividends received from regional
     equity investees


 


      701 

 


    372 

 


  103 

 


  687 

 


  1,715 

   Fixed charges, as below

 

11,071 

 

  22,162 

 

21,087 

 

19,801 

 

17,156 

 

14,920 

   Less: Interest capitalized
     (including AFUDC)


 


(433)




    (983)


  


(853)


 


(455)


 


(220)


 


(68)

 Total earnings, as defined

 

$                 26,157 

 

$                   59,544 

 

$                     44,257 

 

$                   43,517 

 

$                 37,034 

 

$                43,993 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed charges, as defined:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

   Interest on long-term debt (a)

 

$                   6,686 

 

$                   11,577 

 

$                     10,671 

 

$                     9,535 

 

$                   6,655 

 

$                   3,860 

   Interest on rate reduction bonds

 

2,660 

 

5,839 

 

6,723 

 

7,570 

 

8,332 

 

8,994 

   Other interest

 

625 

 

2,430 

 

1,507 

 

1,041 

 

   782 

 

   965 

   Rental interest factor

 

667 

 

1,333 

 

1,333 

 

1,200 

 

1,167 

 

1,033 

   Interest capitalized (including AFUDC)

 

433 

 

   983 

 

   853 

 

455 

 

   220 

 

68 

 Total fixed charges, as defined

 

$                 11,071 

 

$                   22,162 

 

$                     21,087 

 

$                   19,801 

 

$                 17,156 

 

$                14,920 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of Earnings to Fixed Charges

 

2.36 

 

2.69 

 

2.10 

 

2.20 

 

2.16 

 

2.95 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Interest on long-term debt amounts include amortized premiums, discounts and capitalized expenses related to indebtedness.

 

 




Exhibit 31


CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002


I, Leon J. Olivier, certify that:


1.

I have reviewed this quarterly report on Form 10-Q of Western Massachusetts Electric Company (the registrant);


2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiary, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.




Date:  August 6, 2008




/s/

Leon J. Olivier

 

Leon J. Olivier

 

Chief Executive Officer

 

(Principal Executive Officer)




Exhibit 31.1


CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002


I, David R. McHale, certify that:


1.

I have reviewed this quarterly report on Form 10-Q of Western Massachusetts Electric Company (the registrant);


2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiary, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.




Date:  August 6, 2008




/s/

David R. McHale

 

David R. McHale

 

Senior Vice President and Chief Financial Officer

 

(Principal Financial Officer)






Exhibit 32


CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


In connection with the quarterly report of Western Massachusetts Electric Company (the registrant) on Form 10-Q for the period ending June 30, 2008 as filed with the Securities and Exchange Commission (the Report), we, Leon J. Olivier, Chief Executive Officer of the registrant, and David R. McHale, Senior Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:


1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.




/s/

Leon J. Olivier

 

Leon J. Olivier

 

Chief Executive Officer



/s/

David R. McHale

 

David R. McHale

 

Senior Vice President and Chief Financial Officer




Date:  August 6, 2008




A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.